Opinion

Entergy Texas, Inc.// Office of Public Utility Counsel and Public Utility Commission of Texas v. Public Utility Commission of Texas and Texas Industrial Energy Consumers// Office of Public Utility Counsel and Entergy Texas, Inc.

Court: Texas Court of Appeals, 3rd District (Austin)
Filed: Mar 31, 2015
Status: Published
Cited by: 0 cases
Authority: More cited than 3.1%

The opinion

ACCEPTED

03-14-00735-CV

4703327

THIRD COURT OF APPEALS

AUSTIN, TEXAS

3/31/2015 9:04:27 AM

JEFFREY D. KYLE

CLERK

No. 03-14-00735-CV

IN THE FILED IN

3rd COURT OF APPEALS

THIRD COURT OF APPEALS AUSTIN, TEXAS

AT AUSTIN, TEXAS 3/31/2015 9:04:27 AM

JEFFREY D. KYLE

Entergy Texas, Inc., et al., Clerk

Appellants

Public Utility Commission of Texas, et al.,

Appellees

Appeal from the 353rd Judicial District Court, Travis County, Texas

The Honorable John K. Dietz, Judge Presiding

________________________________________________________________

APPELLANT’S BRIEF

OF ENTERGY TEXAS, INC.

_________________________________________________________________

John F. Williams

State Bar No. 21554100

jwilliams@dwmrlaw.com

Marnie A. McCormick

State Bar No. 00794264

mmccormick@dwmrlaw.com

DUGGINS WREN MANN & ROMERO, LLP

600 Congress Ave., Ste. 1900 (78701)

P. O. Box 1149

Austin, Texas 78767-1149

(512) 744-9300

(512) 744-9399 fax

ATTORNEYS FOR APPELLANT

ENTERGY TEXAS, INC.

March 2015

ORAL ARGUMENT REQUESTED

IDENTITY OF PARTIES AND COUNSEL

The following is a list of all parties to the order appealed from and the names

and addresses of all trial and appellate counsel:

Parties: Attorneys:

Entergy Texas, Inc. John F. Williams

Plaintiff in District Court Marnie A. McCormick

Duggins Wren Mann & Romero, LLP

600 Congress Ave., Ste. 1900 (78701)

P. O. Box 1149

Austin, Texas 78767-1149

Counsel in District Court and on Appeal

Public Utility Commission of Texas Elizabeth R. B. Sterling

Defendant in District Court Assistant Attorney General

Environmental Protection Division

Office of the Attorney General

P.O. Box 12548

Austin TX 78711-2548

Counsel in District Court and on Appeal

Office of Public Utility Counsel Sara J. Ferris

Plaintiff/Intervenor in District Court Office of Public Utility Counsel

1701 N. Congress Ave., Ste. 9-180

Austin TX 78711-2397

Counsel in District Court and on Appeal

Cities of Bridge City, et al. Daniel J. Lawton

Plaintiff/Intervenor in District Court Lawton Law Firm PC

12600 Hill Country Blvd., Ste. R275

Austin TX 78738

Counsel in District Court

State Agencies Susan M. Kelley (retired)

Plaintiff/Intervenor in District Court Office of the Attorney General

P. O. Box 12548

Austin TX 78711-2548

Counsel in District Court

Texas Industrial Energy Consumers Meghan Griffiths

Intervenor in District Court Andrews Kurth LLP

111 Congress Ave., Ste. 1700

Austin TX 78701

Counsel in District Court

Rex VanMiddlesworth

Benjamin Hallmark

Thompson Knight LLP

98 San Jacinto Blvd., Ste. 1900

Austin, Texas 78701

Counsel in District Court

TABLE OF CONTENTS

IDENTITY OF PARTIES AND COUNSEL ............................................................ i

TABLE OF CONTENTS ......................................................................................... iii

INDEX OF AUTHORITIES.................................................................................... vi

STATEMENT OF THE CASE ................................................................................ ix

STATEMENT REGARDING ORAL ARGUMENT ............................................. ix

ADMINISTRATIVE RECORD .............................................................................. ix

ISSUES PRESENTED...............................................................................................x

STATEMENT OF FACTS ........................................................................................1

I. Regulatory Framework ....................................................................................1

II. Procedural History ...........................................................................................4

SUMMARY OF THE ARGUMENT ........................................................................5

ARGUMENT AND AUTHORITIES ........................................................................7

I. The Commission erred in disallowing over $11 million associated

with ETI’s unrecovered Hurricane Rita reconstruction costs. ........................7

A. Background ...........................................................................................7

B. The Commission erred as a matter of law in concluding that

PURA required the insurance proceeds to be trued-up in Docket

No. 37744. ...........................................................................................13

C. The Commission also erred in treating the issue as if it had in

fact been resolved in Docket No. 37744. ............................................15

D. The Commission’s order contravenes legislative intent. ....................18

II. The Commission erred in refusing to include any of ETI’s adjustments

to test-year purchased capacity costs in setting rates. ...................................19

A. Background .........................................................................................19

iii

B. The Commission misapplied the standard for adjustments to

test-year expenses. ...............................................................................24

1. Adjustments to test-year data are not extraordinary relief........24

2. Adjustments to test-year data need not be proven with

absolute certainty. .....................................................................26

C. The Commission’s wholesale disallowance of any adjustment

to test-year levels of capacity costs is not supported by

substantial evidence.............................................................................27

1. ETI proved that it will incur an annual capacity cost

increase of $15.8 million under the Frontier contract...............28

2. ETI proved that it will incur an annual capacity cost

increase of $8.1 million under the SRMPA contract. ...............30

3. ETI proved that it will incur an annual capacity cost

increase of $14.1 million under the Calpine contract. ..............31

4. The record does not reasonably support the

Commission’s other reasons for disallowing 100 percent

of these known capacity costs. ..................................................32

a. Load Growth ...................................................................32

b. MSS-1 Costs ...................................................................34

c. MSS-4 Costs ...................................................................36

D. The consequences of the Commission’s decision are extreme

and unjust. ...........................................................................................38

III. The Commission erred in setting ETI’s transmission equalization

(MSS-2) expense at the test-year level. .........................................................39

A. The Commission erred as a matter of law in applying the

standard for adjustments to test-year expenses. ..................................41

B. Additionally, the Commission’s adherence to test-year expense

levels is unsupported by substantial evidence.....................................42

CONCLUSION AND PRAYER .............................................................................43

CERTIFICATE OF COMPLIANCE .......................................................................44

CERTIFICATE OF SERVICE ................................................................................45

APPENDICES .........................................................................................................47

INDEX OF AUTHORITIES

Cases

B.L.M. v. J.H.M., III,

No. 03-14-00050-CV, 2014 WL 3562559 *11 (Tex. App. – Austin Jul. 17,

2014, pet. denied) .................................................................................................17

Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State

of W.Va.,

262 U.S. 679 (1923) ...............................................................................................2

Cameron v. Terrell & Garrett, Inc.,

618 S.W.2d 535 (Tex. 1981) ................................................................................33

Cities of Dickinson v. Public Util. Comm’n of Tex.,

284 S.W.3d 449 (Tex. App. – Austin 2009, no pet.) ...........................................11

City of Corpus Christi v. Public Util. Comm’n of Tex.,

51 S.W.3d 231 (Tex. 2001) ..................................................................................10

City of El Paso v. Public Util. Comm’n of Tex.,

344 S.W.3d 609 (Tex. App. – Austin 2011, no pet.) ................................ 3, 19, 20

City of El Paso v. Public Util. Comm’n of Tex.,

883 S.W.2d 179 (Tex. 1994) ............................................................... 3, 25, 26, 41

Commint Technical Services, Inc. v. Quickel,

314 S.W.3d 646 (Tex. App. – Houston [14th Dist.] 2010, no pet.) ......................16

Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex.,

173 S.W.3d 199 (Tex. App. – Austin 2005, pet. denied) ......................................1

Federal Power Comm’n v. Hope Natural Gas Co.,

320 U.S. 591 (1944) ...............................................................................................2

Idaho Power Co. v. Idaho State Tax Comm'n,

109 P.3d 170 (Idaho 2005) ...................................................................................10

Office of Consumer Counsel v. Department of Public Util. Control,

742 A.2d 1257 (Conn. 2000) ................................................................................10

Office of Consumer Counsel v. Department of Public Util. Control,

905 A.2d 1 (Conn. 2006) .....................................................................................10

Office of Public Util. Counsel v. Public Util. Comm’n of Tex.,

104 S.W.3d 225 (Tex. App. – Austin 2003, no pet.) .............................................2

Starr County v. Starr Industrial Servs., Inc.,

584 S.W.2d 352 (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.) ......................27

State of Texas' Agencies & Institutions of Higher Learning v. Public Util.

Comm’n of Tex.,

450 S.W.3d 615 (Tex. App. -- Austin 2014, pet. requested) ........................ 10, 17

Suburban Util. Corp. v. Public Util. Comm’n of Tex.,

652 S.W.2d 358 (Tex. 1983) ........................................................................... 3, 26

TXU Elec. Co. v. Public Util. Comm’n of Tex.,

51 S.W. 3d 275 (Tex. 2001) (per curiam) ..............................................................8

Woods v. William M. Mercer, Inc.,

769 S.W.2d 515 (Tex. 1988) ................................................................................16

Statutes

Tex. Gov’t Code Ann. § 2001.174 .............................................................. 19, 39, 43

Tex. Gov’t Code Ann. § 2001.190...........................................................................17

Tex. Util. Code Ann. §§ 11.001, et seq. ....................................................................1

Tex. Util. Code Ann. §§ 36.001, et seq. ..................................................................14

Tex. Util. Code Ann. § 36.003 ...................................................................................2

Tex. Util. Code Ann. § 36.051 .................................................................. 2, 7, 25, 41

Tex. Util. Code Ann. §§ 39.001-.359 ........................................................................2

Tex. Util. Code Ann. § 39.452 ...............................................................................2, 8

Tex. Util. Code Ann. § 39.455 .................................................................................33

Tex. Util. Code Ann. § 39.458 ........................................................................ 7, 8, 18

Tex. Util. Code Ann. §§ 39.458-463 .................................................................. 7, 18

Tex. Util. Code Ann. § 39.459 ............................................................................ 7, 13

Tex. Util. Code Ann. § 39.462 ......................................................................... passim

Rules

16 Tex. Admin. Code § 22.222 ................................................................................17

16 Tex. Admin. Code § 25.181 ..................................................................................4

16 Tex. Admin. Code § 25.231 ..................................................................... 3, 24, 41

16 Tex. Admin. Code § 25.234 ..................................................................................3

16 Tex. Admin. Code §§ 25.235-.237 .......................................................................4

vii

16 Tex. Admin. Code § 25.236 ......................................................................... 19, 20

16 Tex. Admin. Code § 25.238 ................................................................................20

Tex. R. Civ. P. 94 .....................................................................................................15

Commission Proceedings

Application of Entergy Gulf States, Inc. for Authority to Change Rates and

to Reconcile Fuel Costs, Docket No. 34800 ........................................................13

Application of Entergy Gulf States, Inc. for Determination of Hurricane

Reconstruction Costs, Docket No. 32907 .................................................... passim

Application of Entergy Texas, Inc. for Authority to Change Rates and

Reconcile Fuel Costs, Docket No. 37744 ............................................................17

viii

STATEMENT OF THE CASE

This is a suit for judicial review of the final order of the Public Utility

Commission of Texas (the “Commission” or “PUCT”) in its Docket Number

39896, a proceeding initiated by Entergy Texas, Inc. (“ETI” or the “Company”) for

authority to change its retail electric rates and reconcile fuel costs. ETI and several

other parties to the contested case sought judicial review of the Commission’s

order.1 The cases were consolidated.2 The district court, Judge John K. Dietz

presiding, reversed the Commission’s order in one respect and summarily affirmed

it in all other respects.3

STATEMENT REGARDING ORAL ARGUMENT

Cases involving public utility regulation usually involve complex regulatory

principles, and this one is no exception. For that reason, the Court’s decisional

process would be aided by oral argument.

ADMINISTRATIVE RECORD

The Administrative Record (“AR”) comprises Joint Exhibits 4-13 of the

Reporter’s Record. Joint Exhibit 13 was sealed per the requirements of Texas Rule

of Civil Procedure 76a.4 Joint Exhibits 1-3 are indices to the record.

Clerk’s Record (“CR”) 5. The Clerk’s Record does not yet contain the petitions filed by parties

other than ETI.

CR 81.

CR 2118.

CR 2109.

ISSUES PRESENTED

1. The Commission disallowed over $11 million of costs that ETI incurred to

restore its system after Hurricane Rita and that no one disputes ETI is

entitled to recover. The Commission decided that ETI should have begun

recovering these costs at the end of a previous rate case, Docket No. 37744,

based upon a PURA provision and what the Commission characterizes as an

ambiguity in the resolution of Docket No. 37744.

a. Did the Commission erroneously interpret PURA as requiring

resolution of this issue in Docket No. 37744, when PURA section

39.462(a) says ETI may recover these costs in “any” proceeding

authorized by Chapter 36?

b. Did the Commission err by requiring ETI to disprove its opponents’

res judicata theory that the order in Docket No. 37744 bars ETI from

seeking recovery of the costs in this case?

c. Does the record reasonably support the Commission’s decision that

the order in Docket No. 37744 required ETI to begin recovering these

costs, when everyone agrees the Commission’s order said nothing

about the issue?

2. The Commission disallowed over $30 million of ETI’s expenses for

purchasing capacity from third parties because the amount was not incurred

in the test year and because the Commission found there was a possibility

that some of the costs might be avoided or offset.

a. Did the Commission err as a matter of law by treating adjustments to

test-year levels of expense as “exceptional” and by refusing to make

any adjustments for anticipated costs?

b. Is every one of the Commission’s multiple theories about how the

costs might be avoided or offset supported by substantial evidence?

3. The Commission refused to make any adjustment to ETI’s test-year level of

“transmission equalization” expense because the parties disagreed about

how big an adjustment was warranted.

a. Did the Commission err as a matter of law by requiring proof of

adjustments to test-year expenses with absolute certainty?

b. Is the Commission’s decision to set this expense at the test-year level

supported by substantial evidence, when every witness who testified

on this issue agreed the test-year level was too low?

STATEMENT OF FACTS

ETI is an investor-owned electric utility.5 ETI provides bundled generation,

transmission, distribution, and customer services to over 400,000 retail customers,

primarily in southeastern Texas.6 During the time periods at issue in this case, ETI

served both wholesale and retail customers.

I. Regulatory Framework

ETI is a subsidiary of Entergy Corporation, which also owns other

subsidiaries, or “operating companies,” including electric utilities in Louisiana,

Arkansas, and Mississippi.7 The utility subsidiaries each own facilities separately,

but they have historically coordinated and shared resources for providing and

transmitting energy.8 This coordination across state lines is governed by the

“Entergy System Agreement,” a tariff approved by the Federal Energy Regulatory

Commission (“FERC”).9 ETI’s wholesale rates are also regulated by the FERC.

See Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex., 173 S.W.3d 199, 207

(Tex. App. – Austin 2005, pet. denied).

The services ETI provides to Texas retail customers are subject to regulation

by the PUCT under the Public Utility Regulatory Act (“PURA”).10 The Texas

AR Binder 31, ETI Exh. 4 (Domino Direct at 1 of 38).

Id.

AR Binder 36, ETI Exh. 39 (Cicio Direct at 6-10 of 75).

Id.

See Tex. Util. Code Ann. §§ 11.001, et seq.

legislature in 1999 ordered electric utilities to “unbundle” their generation,

transmission, distribution, and customer service functions as part of an effort to

introduce competition into the Texas retail electric industry. See Tex. Util. Code

Ann. §§ 39.001-.359. However, in 2009, the legislature amended PURA to require

ETI to cease activities relating to the transition to retail competition. See id.

§ 39.452(i). Accordingly, ETI remains subject to traditional cost-of-service rate

regulation. Id. § 39.452(a).

Under traditional regulation, an electric utility provides service, from the

acquisition to delivery of power, to all requesting customers in a service area at a

Commission-approved “just and reasonable” rate. See Office of Public Util.

Counsel v. Public Util. Comm’n of Tex., 104 S.W.3d 225, 227-28 (Tex. App. –

Austin 2003, no pet.); see also Tex. Util. Code Ann. § 36.003(a). Under PURA

and applicable constitutional principles, a utility is entitled to rates that afford it a

“reasonable opportunity to earn a reasonable return on the utility’s invested capital

used and useful in providing service to the public in excess of the utility’s

reasonable and necessary operating expenses.” Tex. Util. Code Ann. § 36.051;

Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944);

Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State of

W.Va., 262 U.S. 679, 692 (1923). To set rates, the Commission determines each of

these components, which cumulatively are the utility’s “revenue requirement” or

“cost of service.” See, e.g., City of El Paso v. Public Util. Comm’n of Tex., 883

S.W.2d 179, 187 (Tex. 1994); 16 Tex. Admin. Code § 25.231.

The PUCT by rule has adopted a process by which rates are based on a

historical “test year,” adjusted for known and measurable changes. See 16 Tex.

Admin. Code § 25.231(a). The Commission evaluates the reasonableness of the

utility’s expenses, determines the appropriate level of capital investment (or rate

base) and a reasonable rate of return on that investment, and then allocates the total

revenue requirement among the utility’s various classes of customer. Id.

§§ 25.231(b), (c) & .234.

The central goal of this process is to arrive at cost recovery as representative

as reasonably possible of the utility’s “cost situation expected in the future.”

Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358, 366 (Tex.

1983). The utility generally bears the risk that its actual operating expenses will

exceed the expectations incorporated into the rate, while retail customers bear the

converse risk, during the regulatory “lag” between rate cases. City of El Paso v.

Public Util. Comm’n of Tex., 344 S.W.3d 609, 613 (Tex. App. – Austin 2011, no

pet.).

Exceptions to this general rule of risk exist for certain categories of costs,

such as fuel costs and energy efficiency costs. For these types of costs, the utility

has a separate rate or “rider” through which it collects its projected costs. The

utility later must reconcile those revenues to its actual, reasonable costs so that it

recovers no more or less than its actual, reasonable costs for the particular category

of expense covered by the rider. See, e.g., 16 Tex. Admin. Code §§ 25.235-.237 &

§ 25.181.

II. Procedural History

The Company initiated the underlying general rate case because the rates in

effect did not adequately compensate it for its cost of providing service.11 Among

other things, ETI’s third-party purchased power costs were doubling, a study

showed that its current depreciation rates were severely understated, and its actual

return on equity was some three percentage points lower than its then-authorized

return.12 ETI sought a total annual increase of $104.8 million.13 The “test year”

for the Company’s application was July 1, 2010 through June 30, 2011.14 Rates

were proposed to go into effect in June 2012.15

After an evidentiary hearing, four Administrative Law Judges (“ALJs”)

issued a proposal for decision recommending that ETI’s rates be increased by a

total of $28.3 million annually.16 The Commission, with a few exceptions, adopted

AR Binder 31, ETI Exh. 4 (Domino Direct at 7 of 38).

Id. at 7-8.

AR Binder 37, ETI Exh. 55 (LeBlanc Rebuttal at 7 of 14).

AR Binder 31, ETI Exh. 4 (Domino Direct at 8 of 38).

AR Binder 43, Vol. K (5/2/12 Tr. at 1540).

See AR Binder 7, Item 244 (Order on Rehearing at 1).

the proposal for decision and ordered that ETI’s rates be increased by a total of

$27.7 million annually.

ETI appealed several aspects of the final order to the district court.17 Several

parties that intervened in the Commission proceeding, including a group of cities

(“Cities”), the Office of Public Utility Counsel (“OPUC”), and State Agencies,

also appealed.18 The district court sustained one of ETI’s points, reversing the

Commission’s decision on that issue.19 The court summarily affirmed the

Commission’s order in other respects.20 More detailed facts are explained below in

the context of the specific errors ETI brings to this Court.

SUMMARY OF THE ARGUMENT

This case is about several multi-million-dollar outlays that ETI made to

serve its customers, but that the Commission refused to include in ETI’s rates.

First, ETI spent millions of dollars reconstructing its system after Hurricane

Rita. The Commission long ago determined these costs were reasonable and

necessary, and that ETI was entitled to recover them. Nevertheless, the

Commission has now disallowed over $11 million of these costs on the theory that

ETI should have started recovering them after its 2009 rate case. This decision is

CR 5.

Though the separate appeals were consolidated, CR 81, the Clerk’s Record does not yet

contain the petitions filed by parties other than ETI. In any event, after the cases were

consolidated, State Agencies nonsuited their appeal but remained in the case as an intervenor

defendant. CR 2084 & 2085.

CR 2118.

Id.

based upon an erroneous interpretation of a PURA provision. It is also based upon

a legally and factually unsupportable conclusion that ETI should have divined that

it was required to begin recovering these costs after the 2009 rate case, even

though the order in that case said no such thing.

Second, ETI spent millions of dollars purchasing third-party capacity to

serve its customers. Even though the Commission did not find that these purchases

were unreasonable or unnecessary, the Commission refused to include the costs in

ETI’s rates. The Commission’s decision is based upon an erroneous insistence that

test-year data is more important than evidence of what costs the Company expects

to bear when the rates go into effect. It is also based upon several fact-findings

that ETI might be able to avoid or offset some of these costs. These findings do

not support a total disallowance of the purchased capacity costs and are not

rationally based upon the record evidence.

Similarly, ETI spent millions of dollars to pay for its share of the multi-

jurisdictional transmission network that supports service to its customers, and those

costs dramatically increased after the test year. Even though every witness who

testified about this issue agreed that the test-year level of this expense was too low,

the Commission refused to make any adjustment because the witnesses did not

agree on how much of an increase was warranted. This decision is another

example of the Commission’s erroneous application of the standard for calculating

expenses that should be included in rates. It is also unsupported by substantial

evidence.

The effect of all these decisions was that ETI had to bear all these costs at

shareholder expense until its next rate case. ETI, therefore, did not have the

opportunity to earn the reasonable return on its investment to which it is entitled

under PURA. See Tex. Util. Code Ann. § 36.051. Because these decisions were

fraught with error, this Court should reverse them.

ARGUMENT AND AUTHORITIES

I. The Commission erred in disallowing over $11 million associated with

ETI’s unrecovered Hurricane Rita reconstruction costs.

A. Background

In 2005, Hurricane Rita struck the upper Texas coast, causing extensive

damage to southeastern Texas. The next year, the legislature enacted a set of

provisions in PURA that entitles electric utilities like ETI to timely recover

reconstruction costs they reasonably and necessarily incurred as a result of the

hurricane. See Tex. Util. Code Ann. §§ 39.458-463.

The enactment requires the Commission, upon application by a utility, to

determine whether particular hurricane reconstruction costs were reasonably and

necessarily incurred and thus eligible for recovery. Id. §§ 39.459(a)(1) &

39.462(b). This determination need not be made in the context of a base-rate

proceeding under PURA Chapter 36. Id. § 39.462(e).

If, upon a utility’s application, the Commission determines it would benefit

ratepayers for the utility to recover eligible costs through “securitization”

financing,21 as opposed to “conventional financing methods,” the Commission

must adopt a financing order authorizing the utility to issue bonds. Id. § 39.458.

The bonds are repaid or secured by charges to ratepayers in the utility’s service

area. E.g., TXU Elec. Co. v. Public Util. Comm’n of Tex., 51 S.W. 3d 275, 277

(Tex. 2001) (per curiam). Alternatively, a utility is entitled to recover eligible

reconstruction costs in a base rate proceeding “or through any other proceeding

authorized by Subchapter C, Chapter 36” of PURA. Tex. Util. Code Ann.

§ 39.462(a).

In December 2006, ETI’s predecessor22 initiated a proceeding to determine

whether certain of its Hurricane Rita reconstruction costs were eligible for

recovery and securitization.23 The parties to that case reached a settlement and

Securitization is a specialized form of debt financing where repayment of bondholders

achieves a high degree of assurance, resulting in very low bond interest rates.

ETI’s predecessor was Entergy Gulf States, Inc. (“EGSI”). EGSI provided retail electric

service in both Texas and Louisiana. In 2005, the Texas Legislature enacted legislation

providing that EGSI could proceed with and complete jurisdictional separation of its Texas and

Louisiana operations to establish two separate, vertically integrated utilities. See Tex. Util. Code

Ann. § 39.452(e). By January 1, 2008, EGSI had separated into ETI, a Texas-only utility, and

Entergy Gulf States Louisiana, L.L.C., a Louisiana-only utility.

See Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction

Costs, Docket No. 32907 (Jul. 5, 2006 Application). Public filings in Docket No. 32907 and

other Commission dockets may be accessed at the Commission’s interchange:

http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch.asp

by entering the docket number in the “Control Number” field.

agreed that $381,236,384 of the expenses at issue were eligible.24 Because ETI

expected to receive insurance proceeds of $65,700,000 in the future, the settlement

provided that ETI would deduct that amount from its eligible costs.25 The parties

agreed that ETI should be allowed to securitize $381,236,384, plus carrying costs,

minus the $65.7 million estimated insurance proceeds, plus other qualified costs.26

It was understood that the Company might not receive exactly $65,700,000 in

insurance proceeds, so the parties further agreed that after ETI received all of its

insurance payments, a true-up would occur to determine the difference between the

$65,700,000 estimate and the amount actually received.27 The parties agreed that

ETI would accrue interest on the anticipated payments until they were actually

paid, either by insurance companies or ratepayers.28

The Commission approved the parties’ agreement.29 The order provided that

if ETI received more insurance payments than estimated, the excess would be

passed through to ratepayers via a rider.30 But the agreed rider was only for over-

recovery. Neither the settlement nor the order specified a method for recovering

any insurance under-recovery from ratepayers.

See Docket No. 32907 (Nov. 17, 2006, Settlement Agreement at 2 of 10).

Id. at 3 of 10.

Id. at 5 of 10.

Id. at 3 of 10.

Id.

See id. (Dec. 1, 2006, Order at 1).

Id. at FOF 30.

By 2009, ETI had received only $46,013,904 in insurance proceeds,

resulting in a $19,686,096 under-recovery of its actual, eligible hurricane

reconstruction costs.31 ETI carried this unrecovered balance on its books, with

interest, as a regulatory asset32 because the Commission’s order in Docket No.

32907 expressly contemplated that ETI would be authorized to recover these

amounts in the future.33

In 2009, ETI filed a base rate case, Docket No. 37744. By that time, ETI

had recovered most of the insurance proceeds it expected to recover, and it sought

permission to begin recovering the regulatory asset of $19,686,096, plus interest,

on a five-year amortization schedule.34

AR Binder 5, Item 185 (Proposal for Decision at 16).

A “regulatory asset” is a mechanism by which a utility carries a cost on its books as a balance

sheet asset based on the expectation that a regulator will allow the utility to recover the cost over

a period of years in the future instead of at the time the expenditure is made. E.g. Office of

Consumer Counsel v. Department of Public Util. Control, 905 A.2d 1, 7 (Conn. 2006); Idaho

Power Co. v. Idaho State Tax Comm'n, 109 P.3d 170, 173 (Idaho 2005); Office of Consumer

Counsel v. Department of Public Util. Control, 742 A.2d 1257, 1263 (Conn. 2000); City of

Corpus Christi v. Public Util. Comm’n of Tex., 51 S.W.3d 231, 238 (Tex. 2001); State of Texas'

Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615,

646 (Tex. App. -- Austin 2014, pet. requested). Public utility commissions often permit utilities

to recover large capital expenditures on this deferred basis to avoid the “rate shock” that could

result if the costs were passed on to ratepayers all at once. E.g., Office of Consumer Counsel,

905 A.2d at 7; Idaho Power Co., 109 P.3d at 173. A regulatory asset is, therefore, a future debt

of the ratepayers. Office of Consumer Counsel, 905 A.2d at 7. Regulatory assets are recovered

over time from ratepayers on an “amortized” schedule. See Idaho Power Co., 109 P.3d at 173;

Office of Consumer Counsel, 742 A.2d at 1263.

Docket 32907 (Dec. 1, 2006, Order at FOF 28) (authorizing ETI to accrue carrying costs on

estimated insurance proceeds until paid by insurance companies or until the trued-up amount “is

recovered in base rates”); AR Binder 5, Item 185 (Proposal for Decision at 19).

AR Binder 5, Item 185 (Proposal for Decision at 16). Again, as explained above in footnote

32, regulatory assets are traditionally “amortized.” That means they are recovered over a period

of time so they are not charged to ratepayers all at once.

Docket No. 37744 was concluded by a “black box” settlement that did not

mention the Hurricane Rita regulatory asset.35 Neither the parties’ stipulation nor

the PUCT’s order in Docket No. 37744 directed ETI to begin amortizing the

regulatory asset or otherwise prescribed a method for recovering it. Neither

indicated an intent to alter ETI’s rights under PURA section 39.462 and the

Commission’s order in Docket No. 32907.36 ETI, therefore, continued to account

for and accrue interest on the unrecovered regulatory asset.

After Docket No. 37744, ETI received an additional $5.7 million in

insurance proceeds.37 In its next rate case, the one underlying this appeal, ETI

sought permission to begin recovering the updated balance of the reconstruction

costs eligible for recovery. With interest, that balance totaled $26,229,627.38 The

ALJs recommended ETI recover only $15,175,563.39

The ALJs determined that even though the order in Docket No. 37744 did

not say so, ETI should have begun amortizing the regulatory asset on August 15,

2010, the effective date of the rates approved in that docket.40 The ALJs expressed

two rationales for their decision. First, they concluded that PURA required any

In a “black box” settlement, the parties agree to a total amount that a utility can recover

through its rates without specifying any of the individual numbers used to calculate the amount.

See, e.g., Cities of Dickinson, et al. v. Public Util. Comm’n of Tex., 284 S.W.3d 449, 450 (Tex.

App. – Austin 2009, no pet.).

Docket No. 32907, supra (Nov. 17, 2006, Settlement Agreement; Dec. 1, 2006, Order).

AR Binder 37, ETI Exh. 46 (Considine Rebuttal at 18).

Id.; AR Binder 5, Item 185 (Proposal for Decision at 16).

AR Binder 5, Item 185 (Proposal for Decision at 23).

Id. at 21-22.

true-up of insurance proceeds to occur in the first base rate case after the

reconstruction costs were deemed eligible for recovery.41 The ALJs believed that

Docket No. 37744 was that case.42 Second, though they characterized the issue as

a “close call,”43 the ALJs concluded that the amortization of the unrecovered costs

“should be considered as having been approved in Docket No. 37744.”44 They

believed the proposed amortization was not disputed in Docket No. 37744, and that

ETI therefore had the burden of proving the issue was not resolved in the docket.45

Because they believed ETI did not meet that burden, they treated the issue as if it

had already been resolved.46 The ALJs determined that if ETI had begun

amortizing the regulatory asset upon the conclusion of Docket No. 37744, only

$15,175,563 would be left to deal with in this case.47

The Commission adopted the ALJs’ recommendation.48 This decision must

be reversed, because all the rationales for it are flawed.

Id. at 15 & 21-22.

Id. at 16 & 22.

Id. at 20.

Id. at 22.

Id.

Id. at 23.

AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 19-22).

B. The Commission erred as a matter of law in concluding that

PURA required the insurance proceeds to be trued-up in

Docket No. 37744.

The ALJs relied upon PURA section 39.459(c) in concluding that the

insurance proceeds were required to be trued up in the first base rate case after the

reconstruction costs were deemed eligible for recovery.49 Section 39.459(c) reads:

To the extent a utility subject to this subchapter receives insurance

proceeds, governmental grants, or any other source of funding that

compensates it for hurricane reconstruction costs, those amounts shall

be used to reduce the utility’s hurricane reconstruction costs

recoverable from customers. If the timing of a utility’s receipt of

those amounts prevents their inclusion as a reduction to the hurricane

reconstruction costs that are securitized, the commission shall take

those amounts into account in:

(1) the utility’s next base rate proceeding; or

(2) any proceeding in which the commission considers hurricane

reconstruction costs.

Tex. Util. Code Ann. § 39.459 (c) (emphasis added). The Commission, in

adopting the ALJs’ construction of this provision, erred as a matter of law.50

PURA section 39.459(c) requires the Commission to remedy a double-

recovery if a utility receives insurance or grant money for hurricane reconstruction

costs after those same costs have already been securitized. That is the exact

AR Binder 5, Item 185 (Proposal for Decision at 15 & 21-22).

The Commission also erred as a matter of fact in assuming that Docket No. 37744 was ETI’s

first base rate case after the reconstruction costs were deemed eligible for recovery in Docket No.

32907. There was another base rate case filed and decided between Docket Nos. 32907 and

37744. See Application of Entergy Gulf States, Inc. for Authority to Change Rates and to

Reconcile Fuel Costs, Docket No. 34800.

opposite of what happened here. In Docket No. 32907, ETI agreed not to

securitize amounts it expected to recover from insurance. Therefore, in the

language of the statute, the timing of ETI’s receipt of those amounts did not

prevent their inclusion as a reduction to the amounts that were securitized. The

Attorney General conceded in the district court that the wording of section

39.459(c) “is not an exact match to the circumstances of this case.”51 Indeed,

section 39.459(c) is by its plain terms inapplicable.

Section 39.462(a), on the other hand, speaks directly to this situation. It

says:

An electric utility subject to this subchapter is entitled to recover

hurricane reconstruction costs consistent with the provisions of this

subchapter and is entitled to seek recovery of amounts not recovered

under this subchapter … in its next base rate proceeding or through

any other proceeding authorized by Subchapter C, Chapter 36.

Id. § 39.462(a) (emphasis added). There is no question that the proceeding

underlying this appeal was authorized by PURA Subchapter C, Chapter 36. See id.

§ 36.001, et seq. Therefore, the Commission was expressly authorized to address

the issue in this case. It certainly was not statutorily required to address the issue

in Docket No. 37744 or some other particular case.

CR 698 (PUCT Initial Brief at 14).

C. The Commission also erred in treating the issue as if it had

in fact been resolved in Docket No. 37744.

Nothing in the settlement agreement or final order in Docket No. 37744 even

mentioned the regulatory asset, much less a method of recovering it. The ALJs

acknowledged that.52 They also recognized that utilities are typically not allowed

to recover regulatory assets without express approval of the Commission.53 The

ALJs nevertheless concluded that the proposed amortization of the regulatory asset

should be “considered to have been approved” in Docket No. 37744. They

believed that the proposed amortization was not disputed in Docket No. 37744 and

that ETI consequently should be required to prove the issue was not resolved in

Docket No. 37744.54 Both of these assumptions are incorrect.

First, as a matter of law, ETI did not bear the burden of proving what issues

Docket No. 37744 did or did not resolve. The issue of whether Docket No. 37744

bars ETI from seeking particular relief in a subsequent case was a defensive issue

raised by intervenors.55 The argument is really that the order in Docket No. 37744

is res judicata of the reconstruction cost recovery issue. Because that is an

affirmative defense, intervenors bore the burden of proof on the issue. See, e.g.,

Tex. R. Civ. P. 94; Woods v. William M. Mercer, Inc., 769 S.W.2d 515, 517 (Tex.

AR Binder 5, Item 185 (Proposal for Decision at 20-21).

Id. at 21.

Id. at 22.

See, e.g., AR Binder 8 (Cities Exh. 2, Garrett Direct at 11).

1988); Commint Technical Services, Inc. v. Quickel, 314 S.W.3d 646, 651 (Tex.

App. – Houston [14th Dist.] 2010, no pet.).

There is no reasonable basis in the record upon which to conclude that the

parties or the Commission intended ETI to begin amortizing the regulatory asset

years ago. The only reason the intervenors gave in support of their argument was

their allegation that the issue was “undisputed” in Docket No. 37744. It is true that

no party to Docket No. 37744 argued that ETI should not recover the money at

all.56 They could not, given that Docket No. 32907 and PURA clearly entitle ETI

to recover the full amount of its eligible restoration costs. Regardless, the parties’

litigation positions during the contested phase of a proceeding do not inform what

the parties intend when they settle the case, or what the Commission intends in

approving the settlement.

Even assuming for the sake of argument that the parties’ litigation positions

in Docket No. 37744 were relevant, their positions on whether ETI was entitled to

recover the money at all would not be the relevant issue. What would matter is

what the parties’ positions were on how and when ETI should recover the money,

because that is the issue the Commission says was resolved in Docket No. 37744.

Cities’ witness in Docket No. 37744, Jacob Pous, did dispute ETI’s request to

amortize the regulatory asset over a five-year period. He testified that ETI should

See id. at 11.

credit the amount to its storm reserve instead.57 The ALJs were mistaken in

concluding that this issue was uncontested in Docket No. 37744.58 There certainly

is no evidence in this docket that the parties or the Commission intended ETI to

begin amortizing the regulatory asset upon the conclusion of Docket No. 37744.

Given that neither the settlement agreement nor the Commission’s order said

anything about this issue, and especially since the issue was disputed, ETI would

have been unreasonable to “assume” it could begin amortizing the regulatory asset

when Docket No. 37744 was over. As this Court recently recognized, the recovery

of a regulatory asset is a two-step process. First, the Commission allows creation

of the asset, and later, the Commission decides how the utility may recover the

asset in rates. State of Texas' Agencies & Institutions of Higher Learning v. Public

Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App. -- Austin 2014, pet

requested). Here, the settlement and Commission order in Docket No. 32907

established that the hurricane reconstruction costs were reasonable and necessary

and authorized creation of the regulatory asset. But the Company’s proposed

See Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel

Costs, Docket No. 37744 (Pous Direct at 113). Both the Commission and this Court may take

notice of the fact this testimony was filed in Docket No. 37744. Tex. Gov’t Code Ann.

§ 2001.190; 16 Tex. Admin. Code § 22.222(a); B.L.M. v. J.H.M., III, No. 03-14-00050-CV, 2014

WL 3562559 *11 (Tex. App. – Austin Jul. 17, 2014, pet. denied) (not designated for

publication).

In contrast, the ALJs correctly observed that another issue – regarding ETI’s storm reserve

balance -- was disputed in Docket No. 37744. AR Binder 5, Item 185 (Proposal for Decision at

48). They concluded that issue was not resolved by the black box settlement. Id. Using the

ALJs’ own logic, this fact leads to the conclusion that the Hurricane Rita issue was not

adjudicated in Docket No. 37744. Resolving two issues differently based on materially similar

facts is the essence of arbitrary and capricious action.

method of recovering that asset in Docket No. 37744 was a contested issue, and

neither the parties’ settlement nor the Commission’s order resolved the issue in

favor of one party or another. The only reasonable thing for the Company to do

was to maintain the status quo, carrying the balance on its books as a regulatory

asset until the Commission affirmatively addresses how the Company may recover

it.59

D. The Commission’s order contravenes legislative intent.

The Commission’s decision thwarts the legislature’s purpose in enacting the

hurricane reconstruction cost recovery provisions. See Tex. Util. Code Ann.

§§ 39.458-.463. The legislature clearly intended to ensure that utilities that

incurred reconstruction costs as a result of Hurricane Rita would be able to

expeditiously recover those costs in full, with interest. Indeed, the legislature

expressly articulated this purpose in PURA. Id. § 39.458. The effect of the

Commission’s order here is to disallow over $11 million in unrecovered hurricane

reconstruction costs and interest. The order penalizes the utility for, instead of

securitizing all of its hurricane reconstruction costs as authorized by the statute,

opting not to securitize amounts that it anticipated recovering through insurance.

No one has suggested that ETI was unreasonable in estimating its anticipated

Even Cities opined that the Docket No. 37744 settlement should not be interpreted as changing

the status quo unless expressly stated in the settlement agreement or the final order. See AR

Binder 5, Item 185 (Proposal for Decision at 17).

insurance proceeds when the securitization docket was taking place. The

Commission’s reasons for disallowing the amounts that were not ultimately

recovered through insurance are not legally or factually sound. The Court should

reverse the Commission’s disallowance. See Tex. Gov’t Code Ann.

§ 2001.174(b)(2).

II. The Commission erred in refusing to include any of ETI’s adjustments

to test-year purchased capacity costs in setting rates.

A. Background

“Capacity” is the amount of power a utility has available at any given time

to serve customers. Utilities are required to have a percentage surplus or “cushion”

of capacity available in reserve, in case demand exceeds expectations.

Traditionally regulated utilities supply their need for capacity either by owning

generating plants or by buying capacity from someone else.

A utility’s capital investment in building and maintaining its own plant

become a part of its invested capital (or “rate base”), and the utility earns a return

on that investment. The cost of fueling a power plant and other specified variable

“energy” charges incurred to generate power are recoverable dollar-for-dollar as

fuel expenses. 16 Tex. Admin. Code § 25.236(a); City of El Paso, 344 S.W.3d at

614.

Purchases of capacity from third parties are, however, treated differently.

They are simply expenses, and earn no return for the utility. Moreover, the fixed

costs associated with obtaining capacity from third parties may not, absent special

circumstances, be recovered as fuel expenses. 16 Tex. Admin. Code

§ 25.236(a)(4); City of El Paso, 344 S.W.3d at 614. Instead, they are recovered

through base rates. Id.60 Like other base rate expenses, “purchased capacity costs”

are quantified during a “test year,” are adjusted for known and measurable

changes, and become a component of the utility’s revenue requirement that forms

the basis for prospective rates. There is no true-up or reconciliation for the

purchased capacity costs recovered through base rates. Combined with the fact

that there is no opportunity to earn a return on this type of expense, the adverse

financial impact of “regulatory lag” is much more significant for this type of

expense than it is for reconcilable fuel costs.

Before 2009, ETI was under a regulatory directive to position itself for retail

competition, and that directive necessitated that the Company forego long-term

resource procurement. During that time, ETI relied on or “shared” the capacity

from Entergy System resources owned by other Entergy operating companies, and

relied on short- and limited-term resources to reliably serve its retail customers.61

ETI paid for this Entergy System capacity under Schedule MSS-1 of the Entergy

System Agreement. That FERC-approved tariff requires the various Entergy

In some circumstances, Commission rules allow utilities to recover purchased capacity costs

through a rider. See 16 Tex. Admin. Code § 25.238. ETI does not have such a rider.

See AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5-6 of 21); AR Binder 43, Vol. L (5/3/12

Tr. at 1939).

operating companies to make and receive payments according to their relative

share of total system capacity.62 Some Entergy operating companies own a greater

share of Entergy System capacity than they need to serve their own load.63 These

entities are considered “long” on capacity.64 Other companies own less than they

need, and are “short” on capacity.65 Under Schedule MSS-1, “short” companies

pay “long” companies a per-MW rate for the cost of owning these capacity

reserves.66 While it was in regulatory limbo, ETI controlled relatively less

resources compared to its load than other Entergy companies. It, therefore, made

“reserve equalization” payments under Schedule MSS-1.67

In addition to sharing Entergy System capacity under Schedule MSS-1, ETI

also purchased power from specific units owned by other Entergy operating

companies. Those unit-specific purchases were paid for under contracts with those

operating companies under Schedule MSS-4 of the Entergy System Agreement.

Schedule MSS-4 contains a formula that sets the price of power for these purchases

based on the actual cost of producing the power.68

After the legislature in 2009 delayed the onset of retail competition in ETI’s

service area, ETI found it cost effective to begin to substantially increase its

AR Binder 36, ETI Exh. 39 (Cicio Direct at 11-12 of 75).

Id. at 12.

Id.

Id. at 13-14.

AR Binder 35, ETI Exh. 34 (Cooper Direct at 22-23 of 25).

AR Binder 36, ETI Exh. 39 (Cicio Direct at 24-26 of 75).

reliance upon purchases of capacity from third parties.69 ETI did not buy more

third-party capacity simply to serve additional load. Rather, ETI employed the

strategy to serve existing load, reduce its reliance on Entergy capacity resources,

and render ETI less “short” compared to other Entergy entities.70 The strategy also

reduced fuel costs for customers because the third-party resources were by and

large more fuel-efficient than the combined Entergy resources and, as explained

above, there was no return component included in the cost.71

In this case, ETI asked the Commission to recognize the cost of ETI’s

increased reliance on three new third-party purchased capacity contracts. Those

contracts cost ETI some $38 million annually. ETI recognized that these contracts

would enable ETI annually to avoid about $8 million of the costs it paid to Entergy

affiliates for their capacity in the test year. ETI, therefore, asked the Commission

to increase its test-year expenses for purchased capacity by the net amount of about

$30 million for purposes of setting its annual rates.

No party challenged the wisdom of ETI’s entering into any of the new, third-

party contracts or the prices reflected in the contracts. The ALJs, however,

included in ETI’s base rates only purchased capacity costs that were incurred

E.g, AR Binder 35, ETI Exh. 34 (Cooper Direct at 23 of 25).

AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5 of 21); see also id. at 10-11; AR Binder 37,

ETI Exh. 57 (May Rebuttal at 13-15 of 31).

AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper

Rebuttal at 7-8 of 21).

during ETI’s test year.72 The ALJs disallowed 100 percent of the additional

expense associated with the third-party capacity contracts that would be incurred

during the first year rates would be in effect (the “rate year”) and thereafter.73 The

Commission adopted the ALJs’ proposal for decision on this issue.74

The ALJs concluded that ETI had not proven that the costs it would incur as

a result of entering into the third-party purchase capacity contracts were “known

and measurable” adjustments to the utility’s test-year expenses.75 The ALJs found

that there is “substantial uncertainty” about what ETI will be obligated to pay for

the third-party purchased capacity because the third parties might not fully perform

their obligations under the contracts.76 The ALJs suggested that the contract costs

should not be in rates because they may be offset by increased revenues from load

growth.77 The ALJs further found there is “substantial uncertainty” about how

much money the third-party purchased power capacity contracts will enable ETI to

avoid paying to other Entergy entities under Schedule MSS-1 of the Entergy

System Agreement.78 The source of this perceived uncertainty was apparently the

ALJs’ view that the net costs were difficult to quantify because the calculations

AR Binder 5, Item 185 (Proposal for Decision at FOF 86).

Id. at FOF 73 & 86.

AR Binder 7, Item 244 (Order on Rehearing at 1 & 7).

AR Binder 5, Item 185 (Proposal for Decision at 108).

Id. at FOFs 77-78.

Id. at 109 & FOFs 84.

Id. at FOFs 75, 76, & 79-82.

involve projections and “complex” formulae and “variables.”79 Rather than

accepting any of the calculations in evidence or adopting a result within the range

of these recommendations, the ALJs simply disallowed the entire adjustment.80

The Commission’s order adopting these recommendations constitutes error of law

and is not supported by substantial evidence.

B. The Commission misapplied the standard for adjustments

to test-year expenses.

The fundamental error in the Commission’s order is that it misapplies the

legal standard for determining what expenses should be included in rates. The

order adopts the ALJs’ erroneous view that an adjustment to test-year data is

somehow extraordinary or “exceptional” rate relief.81 The ALJs also took the view

that to the extent additional costs are based on anticipated changes, they cannot be

“known and measurable.”82 These assumptions are wrong as a matter of law.

1. Adjustments to test-year data are not extraordinary

relief.

To determine what a utility’s reasonable and necessary expenses are, the

Commission determines “the electric utility’s historical test year expenses as

adjusted for known and measurable changes.” 16 Tex. Admin. Code § 25.231(b).

Under the rule, known and measurable changes have equal weight with historical

Id. at 108.

Id. at 109.

Id. at 108; AR Binder 7, Item 244 (Order on Rehearing at 1).

AR Binder 5, Item 185 (Proposal for Decision at 102).

test-year levels. That makes sense, because PURA does not limit a utility’s

recoverable expenses to those incurred in a historical test year. Rather, PURA

guarantees a utility a reasonable opportunity to earn a reasonable return on its

investment over and above its “reasonable and necessary expenses.” Tex. Util.

Code Ann. § 36.051. The goal of ratemaking is to set utility rates that will meet

the utility’s and customers’ needs in the future, not the past, as rates are set on a

prospective basis.

The Texas Supreme Court has confirmed that making known and

measurable adjustments is a critical component of establishing the costs upon

which rates are set, and not a rare exception to the use of test-year cost levels. The

Court has explained that “changes occurring after the test period, if known, may be

taken into consideration by the regulatory agency to help mitigate the effects of

inflation and in order to make the test year data as representative as possible of

the cost situation that is apt to prevail in the future.” City of El Paso v. Public

Util. Comm’n of Tex., 883 S.W.2d 179, 188 (Tex. 1994) (emphasis added).

The recognition of changes to test-year data is especially critical in a case

such as this one, where the inability to recover substantial post-test-year expenses

inevitably causes ETI to recover an inadequate return, contrary to the requirements

of PURA’s fundamental cost-recovery standards. See Tex. Util. Code Ann.

§ 36.051. The Commission’s conclusion that a utility is somehow less entitled to

expenses that occur beyond the test year is contrary to PURA and judicial

precedent, and its erroneous application of the known and measurable standard

tainted the entirety of its decision on this issue. This is reason enough to reverse

the Commission’s decision.

2. Adjustments to test-year data need not be proven

with absolute certainty.

The quantum of proof required to establish adjustments to test-year data is

not greater than the quantum required to establish the test-year data itself. The

Texas Supreme Court has held that known and measurable adjustments should be

made if they reflect costs that will be “actually realized,” can be “anticipated with

reasonable certainty,” and if they are representative of the costs “apt” to prevail in

the future. See City of El Paso, 883 S.W.2d at 188; Suburban Util. Corp., 652

S.W.2d at 362. The standard is not an impossible-to-meet requirement of absolute

or virtual certainty. Suburban Util. Corp., 652 S.W.2d at 362. Contrary to its

ruling regarding purchased capacity, the Commission in this and other cases has

routinely adopted known and measurable adjustments that involve estimates and

uncertainty.83 In rejecting ETI’s proposed adjustments to test-year purchased

capacity expense, the Commission did not acknowledge or discuss the statute, rule,

judicial precedent, or regulatory precedent that guide its inquiry. The decision is

E.g., AR Binder 5, Item 185 (Proposal for Decision at 68 (short-term asset update), 163-64

(payroll adjustments), & 182-86 (ad valorem tax rate update)).

contrary to and inconsistent with all those authorities. Under the Commission’s

analysis, known and measurable changes routinely adopted by the Commission

would never be allowed. The Commission’s ruling is, therefore, arbitrary and

capricious. See Starr County v. Starr Industrial Servs., Inc., 584 S.W.2d 352, 355-

56 (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.). This is another reason the

decision must be reversed.

C. The Commission’s wholesale disallowance of any

adjustment to test-year levels of capacity costs is not

supported by substantial evidence.

The proposed adjustments for third-party purchased capacity expenses are

attributable to three contracts the parties call the Frontier, Calpine, and Sam

Rayburn Municipal Power Agency (“SRMPA”) contracts. ETI established with

reasonable certainty what costs it would incur under each of these contracts while

the rates being set in this case would be in effect. The Commission did not discuss

the contracts separately, but ruled on them in the aggregate. The Commission said:

77. ETI’s projection of its rate-year third-party capacity contract

payments includes numerous assumptions, one of which is that

every single third-party supplier will perform at the maximum

level under the contract, even though that assumption is

inconsistent with ETI’s historical experience.

78. There is substantial uncertainty with regard to ETI’s projection

of its rate-year third-party capacity contract payments.84

AR Binder 7, Item 244 (Order on Rehearing at FOFs 77-78); see also AR Binder 5, Item 185

(Proposal for Decision at 108-109).

These findings are not supported by substantial evidence. As discussed

below, the adjustments were based on contracts already in place before and during

the rate year. The contracts had clearly and specifically ascertainable prices and

quantities, which were in evidence. No one disputed that ETI will pay money

under these contracts. Rather, some parties speculated that ETI might not have to

pay the full amount of these contracts because suppliers might not perform

perfectly. Performance under each of the contracts is reasonably assured. There is

no reasonable uncertainty regarding the outcome under any of these contracts,

certainly none sufficient to support a finding that none of these contract costs are

“apt to prevail” in the near future.

1. ETI proved that it will incur an annual capacity cost

increase of $15.8 million under the Frontier contract.

There is no reasonable basis in the evidence for the Commission’s finding

that the costs of the Frontier contract are uncertain. ETI has had a contract with

Frontier for years, leading up to and including the first ten months of the test

year.85 In the second-to-last month of the test year, ETI increased the annual

amount of power it purchased under the Frontier contract from 150 MW to 300

MW.86 Applying the language of the Texas Supreme Court, the 150 MW increase

in capacity and capacity cost was “actually realized” in the test year. But because

AR Binder 43, Vol. L (5/3/12 Tr. at 1938 & 1941).

Id. at 1942 & 1959.

the step-up happened late in the test year, the test year does not reflect the full

amount of expense ETI will incur going forward under the Frontier contract.87 No

witness challenged ETI’s quantification of what this contract would cost ETI

during the rate year.

On cross-examination at the hearing, ETI’s witness Cooper acknowledged

that ETI’s purchased capacity contracts include provisions that authorize ETI to

reduce its payments if the counter-party does not perform.88 He explained that ETI

did not assume any reduction in future payments for poor performance because in

the past, any such adjustments have been “relatively minor.”89 ETI’s witness May,

who quantified the increase in annual Frontier costs at $15.8 million, confirmed

that ETI has “quite a bit of experiences” with the contract, and a “good

understanding of what the costs are today and what the costs will be in the future”

under the contract.90 The other parties did not produce evidence to the contrary.

It is simply not reasonable to conclude, based upon this record, that there is

“substantial uncertainty” about what ETI’s annual expenses will be in connection

with the Frontier increase. The Commission’s findings insofar as they implicate

this contract are not supported by substantial evidence.

Id. at 1942.

AR Binder 43, Vol. F (4/26/12 Tr. at 705-06); see also id. at 682.

Id. at 705.

AR Binder 43, Vol. L (5/3/12 Tr. at 1942).

2. ETI proved that it will incur an annual capacity cost

increase of $8.1 million under the SRMPA contract.

During the test year, ETI executed a 25-year agreement with SRMPA for

225 MW of capacity.91 Power started flowing under the contract on December 1,

2011, just five months after the end of the test year, well before intervenors filed

their testimony in March 2012, and well before the conclusion of the proceeding

under review.92 All of the capacity contracted for was allocated to ETI.93 The

price of this contract is a “very straightforward $3 per kW a month.”94 It is “very

easy to calculate what those known and measurable costs are.”95 $3.00 x 225,000

kW = $675,000 per month. At $675,000 per month, the contract will cost $8.1

million annually. No witness challenged ETI’s quantification of the annual costs

of the SRMPA contract. In addition, the SRMPA contract commits “System

Capacity,” meaning multiple network resources and substitute resources are

designated to supply the capacity. There is no evidence in the record that

SRMPA’s entire portfolio of network resources is likely to be simultaneously

unavailable.

There is, therefore, no evidence in the record that there is “substantial

uncertainty” about whether SRMPA will perform the contract, or what the annual

AR Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25).

See id.

Id. at 17 & 19 of 25.

AR Binder 43, Vol. L (5/3/12 Tr. at 1944).

Id.

costs of the contract will be. The Commission’s findings insofar as they implicate

this contract are not supported by substantial evidence.

3. ETI proved that it will incur an annual capacity cost

increase of $14.1 million under the Calpine contract.

ETI purchased capacity from Calpine Energy Services under a one-year

contract in effect from June 1, 2008 through May 31, 2009.96 In 2009, ETI entered

into a ten-year purchased power agreement with Calpine to purchase 485 MW of

capacity from its Carville Energy Center.97 Purchases under this contract were set

to begin on June 1, 2012, the beginning of the rate year for this case.98 Fifty

percent of the contract was allocated to ETI.99

The resource had been under contract with the Entergy system for some

time, and the Entergy companies have significant experience with the pricing and

costs under the contract. The most recent contract simply allocated the resource

differently to reflect the fact that the “overhang of retail competition” had been

lifted for ETI.100 Because of ETI’s experience with Calpine, the capacity costs are

“well known.”101 The contract sets out specific capacity quantities and prices, and

includes default and other terms to ensure performance. ETI’s historical

experience with the Calpine resource establishes that any deviations from the

AR Binder 35, ETI Exh. 34 (Cooper Direct at 21-22 of 25).

Id. at 16.

Id.

Id. at 19 of 25.

100

See AR Binder 43, Vol. L (5/3/12 Tr. at 1938).

101

Id. at 1942.

negotiated contract payments will be “very, very small.”102 Both parties to the

contract intend and are incentivized to perform such that they will get the full

benefits of the capacity and price under the contract.103 ETI projected the annual

cost of the Calpine contract will be $14.1 million.104

No witness challenged ETI’s quantification of the costs associated with the

Calpine contract. There is no evidence in the record that there is “substantial

uncertainty” about whether Calpine will perform the contract, or what the annual

costs of the contract will be. The Commission’s findings insofar as they implicate

this contract are not supported by substantial evidence.

4. The record does not reasonably support the

Commission’s other reasons for disallowing 100

percent of these known capacity costs.

a. Load Growth

Intervenors and Commission staff championed multiple theories they alleged

would offset ETI’s additional expense under these three contracts. One such

theory` was that the cost increase is not known and measurable because it may be

offset by load growth that occurs after the test year.105

If it were appropriate to consider future load growth in setting base rates,

PURA or the Commission’s rules would say so. Indeed, there are other instances

102

Id.

103

Id. at 1942-43.

104

AR Binder 8 (Cities Exh. 4B [Highly Sensitive], Goins Direct Exh. DWG-2).

105

AR Binder 5, Item 185 (Proposal for Decision at 109); AR Binder 7, Item 244 (Order on

Rehearing at FOF 84).

in which PURA does specify that the utility’s recovery of costs should be subject

to an offsetting load growth adjustment. See, e.g., Tex. Util. Code Ann. § 39.455

(utility entitled to recover specified incremental capacity costs “adjusted for load

growth”). For base rates, the legislature has left load growth out of the equation,

so that it may serve as a source of revenue to address other future cost increases

and avoid or defer additional rate increases. The legislature’s inclusion of “load

growth” language for specific circumstances but not base rates is evidence the

legislature did not intend it to apply generally. Cameron v. Terrell & Garrett, Inc.,

618 S.W.2d 535, 540 (Tex. 1981).

Even if load growth could properly be considered, however, it does not

support a wholesale disallowance of the increased purchased capacity costs. First,

the load growth that intervenors suggested would occur would not fully materialize

for at least two years.106 It could not logically offset the third-party capacity cost

increases ETI began to experience during or shortly after the test year.

Second, Cities witness Goins is the only intervenor witness who attempted

to quantify a load growth adjustment, and he quantified it at $15.8 million – a far

cry from the $38 million in increased purchased capacity expense that ETI proved

it would incur.107 Moreover, Mr. Goins’s proposal overstated retail load growth

106

AR Binder 43, Vol. J (5/1/12 Tr. at 1299-1300 [Confidential]).

107

AR Binder 8 (Cities Exhs. 4 & 4B [Highly Sensitive], Goins Direct at 9 & 16-19).

significantly and attempted to predict events beyond the rate year.108 It does not

provide a reasonable basis for a known and measurable change at all, much less

one that negates all $38 million of ETI’s third-party capacity contract costs.109

The large gap between Mr. Goins’s speculative adjustment and the known

costs ETI sought illustrates how far the Commission has strayed from setting rates

at a level that will enable ETI to recover the costs it reasonably expects to incur

when the rates are in effect. In any event, the Commission’s reliance on the load

growth theory to deny ETI any adjustment for its post-test-year increases in third-

party purchased capacity costs is not supported by substantial evidence.

b. MSS-1 Costs

Another “offset” theory that the Commission adopted concerned the amount

of money ETI might save under Schedule MSS-1 as a result of the new third-party

purchased capacity contracts. The Commission found that the impact the contracts

would have on ETI’s “reserve equalization” payments under Schedule MSS-1 was

substantially uncertain, because the calculation of MSS-1 costs depends on

“numerous assumptions.”110 The record does not support a wholesale disallowance

of ETI’s third-party capacity cost increases on this ground.

108

Id. at 17-19.

109

AR Binder 37, ETI Exh. 57 (May Rebuttal at 9-11 of 31); AR Binder 43, Vol. I (5/1/12 Tr. at

pp. 1296-1306, 1316-1324 [Confidential]).

110

AR Binder 5, Item 185 (Proposal for Decision at 108); AR Binder 7, Item 244 (Order on

Rehearing at 1 & FOFs 75-76).

Company witness Cooper testified that the MSS-1 cost adjustment is a

straightforward calculation.111 While it is true that the MSS-1 amount is dependent

on the relative load responsibility of ETI, that relative change in load responsibility

was factored into the Company’s calculation.112

Evidence from other parties regarding the MSS-1 costs likewise does not

provide substantial evidence justifying a wholesale disallowance of the third-party

contract costs. Cities, in fact, adopted ETI’s calculation of MSS-1 impacts.113 And

though TIEC argued on one hand that ETI’s MSS-1 expense would increase over

test-year levels,114 the evidence, including TIEC’s, is undisputed that MSS-1 costs

go down as ETI adds new capacity contracts.115 In fact, the MSS-1 costs decreased

during the test year and reached test-year lows during the last two months (when

the new Frontier contract was first put in place).116 TIEC’s recommendations

regarding MSS-1 costs are contrary to reality and all the record evidence. They

certainly do not provide a reasoned basis to reject all of ETI’s proposed increase in

third-party purchased capacity costs.

111

AR Binder 43, Vol. L (5/3/12 Tr. at 1947).

112

See AR Binder 35, ETI Exh. 34 (Cooper Direct at 20 of 25 & ETI Exh. 34A RRC-1 [Highly

Sensitive]).

113

AR Binder 9, Cities Exh. 6 (Nalepa Direct at 17).

114

AR Binder 41, TIEC Exh. 1 (Pollock Direct at 26).

115

AR Binder 41, TIEC Exh. 1D (Pollock Direct at 22, Table 1); AR Binder 9, Cities Exh. 6

(Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]).

116

See AR Binder 9, Cities Exh. 6 (Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]).

c. MSS-4 Costs

The Commission also found that the impact the purchased capacity contracts

would have on MSS-4 costs (costs of unit-specific purchases from other Entergy

operating companies) was substantially uncertain because the calculation of MSS-4

costs depends on “complex mathematical formulae that utilize numerous

variables.”117 However, as shown in the proposal for decision adopted by the

Commission, the adjusted MSS-4 costs sought by the Company are lower than the

test-year level of MSS-4 costs awarded by the Commission. As the Commission

further acknowledged, “while the purchases pursuant to MSS-4 [from test year to

rate year] remain fairly stable, the third-party purchases will substantially increase,

with a somewhat corresponding decrease for purchases pursuant to MSS-1.”118

In other words, the Commission recognized that the known and measurable

adjustment to the test-year amount was driven by third-party purchases, not MSS-4

purchases. The small difference between the test-year and rate-year levels

associated with MSS-4 purchases, under the Commission’s own observations, is

not material to determining the merits of ETI’s proposed purchased power cost

adjustments. In short, alleged uncertainty regarding the rate-year level of MSS-4

117

AR Binder 7, Item 244 (Order on Rehearing at FOFs 79-82).

118

AR Binder 5, Item 185 (Proposal for Decision at 100); AR Binder 7, Item 244 (Order on

Rehearing at 1, adopting Proposal for Decision).

expense is not a reasonable basis for the Commission to reject ETI’s additional

third-party purchased power expense.

Even assuming arguendo that the Commission’s rejection of the Company’s

adjustment to MSS-4 expense is material to the resolution of this issue, the

evidence regarding MSS-4 expense does not support rejection of the entire increase

in third-party purchased capacity costs. Similar to ETI, Cities’ and TIEC’s

adjustments for MSS-4 costs in all but one respect varied only marginally from the

test year. They come nowhere near to offsetting the entire cost of the third-party

contracts.119 Cities and TIEC proposed MSS-4 reductions that were materially

larger than ETI’s120 only because one of ETI’s Arkansas affiliate contracts (the

“WBL” contract) was set to terminate after the test year. Intervenors’ argument

was based on the flawed assumption that ETI would take no action to replace the

WBL contract. To the contrary, the evidence was undisputed that ETI was short of

capacity and in fact extended the very contract in question.121 The dispute over

how much ETI might save in MSS-4 costs does not rationally support a

disallowance of the entire increase for the new purchased capacity contracts

119

AR Binder 41, TIEC Exh. 1 (Pollock Direct at Exh. JP-1) (Line 4 shows $1.4 million

reduction to test year amount of affiliate contracts)); AR Binder 8, Cities Exh. 4B (Goins Errata

3 Exh. DWG-2 [Highly Sensitive]) (less than $3 million reduction to test-year costs for affiliate

contracts excluding WBL).

120

$12.7 million and $11.1 million, respectively.

121

AR Binder 43, Vol. E (4/26/12 Tr. at 687-88 & 696); AR Binder 37, ETI Exh. 47 (Cooper

Rebuttal at 5 of 21); AR Binder 43, Vol. L (5/3/12 Tr. at 1946).

D. The consequences of the Commission’s decision are extreme

and unjust.

The three new third-party purchased power contracts that drive ETI’s

requested adjustment to test-year capacity costs benefit customers tremendously.

They increase the capacity of ETI resources by 618 MW (150 by the Frontier

contract, 225 by the SRMPA contract, and 243 by the half of the Calpine contract

allocated to ETI). They result in substantial fuel savings for customers because of

their diverse fuel resources and efficient heat rates.122 Customers will benefit from

those savings on a dollar-for-dollar basis in fuel reconciliations. While the third-

party owners of the capacity resources profit from the capacity payments ETI must

make, and the retail customers of ETI benefit from the superior heat rates and

resulting fuel savings, the Commission’s order forces the middleman – ETI –to pay

for the capacity with shareholder funds.

The Commission’s draconian adherence to the test-year data and incorrect

application of the standard for making adjustments to that data are reasons alone to

reverse the decision, because they taint every one of the Commission’s findings

discussed above. Even disregarding those errors, none of the Commission’s

findings rationally justifies the disallowance of 100 percent of the cost increase

resulting from the three new contracts. Because the Commission did not quantify

122

AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper

Rebuttal at 7-8 of 21).

how much of a disallowance it made upon each individual theory, if this Court

finds any of the findings are unsupported by substantial evidence, it must reverse

the whole disallowance and remand to the Commission for further consideration.

This Court may not decide fact issues the Commission did not. Tex. Gov’t Code

Ann. § 2001.174(1).

III. The Commission erred in setting ETI’s transmission equalization (MSS-

2) expense at the test-year level.

The Commission also erred in refusing to make any adjustment for another

known and measurable increase in ETI’s expenses after the test year. The Entergy

system transmission grid is a large network, the various pieces of which are owned

by individual Entergy operating companies. The network, however, is integrated

and operated for the mutual benefit of all of the Entergy operating companies.123

In any given month, some of the operating companies may be “long” on the

amount of transmission capacity they own. That is, they own a portion of the

transmission capacity that is greater than their share of the overall load placed on

the transmission system. Other operating companies may be “short” on capacity.

The Entergy System Agreement includes a FERC-approved Schedule MSS-2 that

equalizes the ownership costs of certain high-voltage transmission facilities among

the operating companies. The long operating companies receive MSS-2 payments

123

AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. C (4/25/12 Tr. at

450); AR Binder 43, Vol. F (4/27/12 Tr. at 793).

from the short operating companies for the use of their transmission facilities so

that each pays its fair share of the total ownership costs of the shared system on a

monthly basis.124

Over the course of the test year, ETI was short, so it paid a total of

$1,753,797 in MSS-2 payments to various other operating companies.125 But

ETI’s MSS-2 expenses increased at the end of the test year and continued to

increase after the test year.126 ETI anticipated these costs would increase even

more by the rate year because of transmission projects that were planned to go into

service by the rate year.127 ETI calculated that its MSS-2 expenses would be $10.7

million annually by the rate year.128 ETI sought to include that level of its expense

in its rates.

The ALJs recommended that the Commission disallow any increase in MSS-

2 expense over the test-year level. They found that the increased expenses were

not “known and measurable,” again because the MSS-2 calculation depends on

variables and projections, and because not all the projects ETI included in its

124

AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. F (4/27/12 Tr. at

731 & 735-36).

125

AR Binder 43, Vol. F (4/27/12 Tr. at 724 & 737); AR Binder 9, Cities Exh. 28.

126

AR Binder 9, Cities Exh. 29.

127

AR Binder 43, Vol. F (4/27/12 Tr. at 761); AR Binder 37, ETI Exh. 59 (McCulla Rebuttal at

2-3 of 12).

128

AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738 &

760).

calculation were in service during the test year.129 The Commission adopted the

ALJs’ recommendation that only the test-year level of MSS-2 expense should be

included in ETI’s rates.130

A. The Commission erred as a matter of law in applying the

standard for adjustments to test-year expenses.

The Commission’s decision is flawed as a matter of law for the same reason

its decision about purchased capacity costs is flawed. That is, the goal of

ratemaking is to give the utility a reasonable opportunity to earn a reasonable

return on its investment over and above its reasonable and necessary expenses.

Tex. Util. Code Ann. § 36.051. Commission Rule 25.231 mirrors this principle.

16 Tex. Admin. Code 25.231. This undertaking cannot lawfully turn on the

manner in which the calculation is made, or on the number of inputs to the

calculation. The Commission cannot arbitrarily rely upon test-year levels of

expense to the extent they are proven not to represent the level of expense the

utility is reasonably anticipated to bear in the rate year, or that is “apt to prevail in

the future.” City of El Paso, 883 S.W.2d at 188. If a change is known and can

reasonably be measured, the Commission must make it.

None of the opposing parties’ witnesses refuted that the projects underlying

ETI’s proposed MSS-2 adjustment were already approved and in process, or that

129

AR Binder 5, Item 185 (Proposal for Decision at 116 & FOFs 87-93).

130

AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 87-94).

they will be completed. No intervenor or Staff witness offered any testimony or

evidence casting doubt on the reasonableness of the construction cost estimates.

Their position was simply that if there is any possibility of uncertainty or

variability in the elements of an adjustment to test-year data, it must be denied.

The Commission erred as a matter of law in adopting that standard.

B. Additionally, the Commission’s adherence to test-year

expense levels is unsupported by substantial evidence.

It is undisputed that ETI’s test-year level of MSS-2 expense was too low.

Every witness testifying on the issue recognized that the test-year amount is too

small and should be updated based on more recent, actual payment information.

ETI proffered evidence that by the time of the hearing, its annualized MSS-2

expenses based upon actual, known, historical investment exceeded test-year

levels by about $6.7 million, and its rate-year MSS-2 expenses would exceed test-

year levels by almost $9 million.131 TIEC witness Pollock annualized the last six

months of the test-year expense, increasing it by a million dollars.132 Cities

witness Goins also rejected the test-year expense level and instead used a more

recent 12-month period of actual payments, including six months that occurred

after the test year. He recommended the Commission include an annual expense of

131

AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738, 760,

763, 780, & 783-84).

132

AR Binder 41, TIEC Exh. 1 (Pollock Direct at 32-33).

$4.1 million in ETI’s rates, exceeding the test year by almost $2.5 million.133

Indeed, Cities Exhibit 29 includes the MSS-2 payment for every month from

January 2010 to February 2012. It shows that MSS-2 costs have steadily increased

every month from the last month of the test year, and in fact have doubled since the

last month of the test year.134 No witness testified that the test year was

representative of the expense ETI would bear during the rate year. The

Commission’s decision that the test-year level of MSS-2 expense is sufficient is

simply not supported by any evidence in the record.

Viewing the evidence as a whole, there is no reasonable basis for a

conclusion that the test-year level of $1.7 million is representative of costs apt to

prevail in the future. The Commission’s ruling is, therefore, unsupported by

substantial evidence and must be reversed. Tex. Gov’t Code Ann.

§ 2001.174(b)(2).

CONCLUSION AND PRAYER

For all these reasons, Entergy Texas, Inc. respectfully requests this Court

reverse the district court’s judgment insofar as it affirms the Public Utility

Commission’s order in the respects discussed above. ETI requests the Court

remand the case to the Commission for further proceedings consistent with the

133

AR Binder 8, Cities Exh. 4 (Goins Direct at 21-22).

134

AR Binder 9, Cities Exh. 29 (Response of ETI to Cities RFI 5-1).

Court’s decision. Entergy Texas, Inc. further requests its costs of court and any

other relief to which it may show itself justly entitled.

Respectfully submitted,

/s/ Marnie A. McCormick

John F. Williams

State Bar No. 21554100

Marnie A. McCormick

State Bar No. 00794264

mmccormick@dwmrlaw.com

DUGGINS WREN MANN & ROMERO, LLP

P. O. Box 1149

Austin, Texas 78767-1149

(512) 744-9300

(512) 744-9399 fax

ATTORNEYS FOR APPELLANT

ENTERGY TEXAS, INC.

CERTIFICATE OF COMPLIANCE

I certify that this document contains 10,765 words in the portions of the

document that are subject to the word limits of Texas Rule of Appellate Procedure

9.4(i), as measured by the undersigned’s word-processing software.

/s/ Marnie A. McCormick

Marnie A. McCormick

CERTIFICATE OF SERVICE

The undersigned counsel certifies that the foregoing document was

electronically filed with the Clerk of the Court using the electronic case filing

system of the Court, and that a true and correct copy was served on the following

lead counsel for all parties via electronic service on the 31st day of March, 2015:

Elizabeth R. B. Sterling

Environmental Protection Division

Office of the Attorney General

P. O. Box 12548 (MC 066)

Austin TX 78711-2548

Counsel for Appellee Public Utility Commission of Texas

Rex D. VanMiddlesworth

Benjamin Hallmark

Thompson Knight LLP

98 San Jacinto Blvd., Ste. 1900

Austin TX 78701

Counsel for Intervenor Texas Industrial Energy Consumers

Susan M. Kelley (retired)135

Administrative Law Division

Office of the Attorney General

P. O. Box 12548

Austin TX 78711-2548

Counsel for Intervenor State Agencies

Sara Ferris

Office of Public Utility Counsel

1701 N. Congress Ave., Ste. 9-180

P. O. Box 12397

Austin TX 78711-2397

Counsel for Intervenor Office of Public Utility Counsel

135

State Agencies have not yet appeared or designated a new lead counsel in this appeal.

Daniel J. Lawton

LAWTON LAW FIRM PC

12600 Hill Country Blvd., Ste. R-275

Austin TX 78738

Counsel for Cities of Anahuac, et al.

/s/ Marnie A. McCormick

Marnie A. McCormick

APPENDICES

A. ALJs’ Proposal for Decision in Docket No. 39896

B. Commission's Order on Rehearing in Docket No. 39896

C. District Court's Final Judgment

D. Commission’s Final Order in Docket No. 37744

APPENDIX A

ALJ's Proposal for Decision in Docket No. 39896

SOAH DOCKET NO. XXX-XX-XXXX

PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE

INC. FOR AUTHORITY TO CHANGE §

RATES, RECONCILE FUEL COSTS, § OF

AND OBTAIN DEFERRED §

ACCOUNTING TREATMENT § ADMINISTRATIVE HEARINGS

PROPOSAL FOR DECISION

TABLE OF CONTENTS

I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4]........ 1

II. JURISDICTION AND NOTICE ......................................................................... 2

III. PROCEDURAL HISTORY ................................................................................. 2

IV. EXECUTIVE SUMMARY .................................................................................. 4

A. Rate Base................................................................................................................ 4

1. Capital Investment .................................................................................... 4

2. Hurricane Rita Regulatory Asset ............................................................ 4

3. Prepaid Pension Asset Balance ................................................................ 5

4. FIN 48 Tax Adjustment ............................................................................ 5

5. Cash Working Capital .............................................................................. 5

6. Self-Insurance Storm Reserve ................................................................. 5

7. Coal Inventory........................................................................................... 5

8. Spindletop Gas Storage Facility .............................................................. 5

9. Short Term Assets ..................................................................................... 6

10. Acquisition Adjustment ............................................................................ 6

11. Capitalized Incentive Compensation ...................................................... 6

B. Rate of Return and Capital Structure ................................................................ 6

C. Cost of Service ....................................................................................................... 7

1. Purchased Power Capacity Expense ....................................................... 7

2. Transmission Equalization (MSS-2) Expense ........................................ 7

3. Depreciation Expense ............................................................................... 7

4. Labor Costs................................................................................................ 7

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PUC DOCKET NO. 39896

5. Interest on Customer Deposits................................................................. 8

6. Property (Ad Valorem) Tax Expense ...................................................... 9

7. Advertising, Dues, and Contributions..................................................... 9

8. Other Revenue Related Adjustments ...................................................... 9

9. Federal Income Tax .................................................................................. 9

10. River Bend Decommissioning Expense ................................................... 9

11. Self-Insurance Storm Reserve Expense .................................................. 9

12. Spindletop Gas Storage Facility ............................................................ 10

D. Affiliate Transactions ......................................................................................... 10

E. Jurisdictional Cost Allocation............................................................................ 10

F. Class Cost Allocation .......................................................................................... 11

1. Renewable Energy Credit Rider............................................................ 11

2. Class Cost Allocation .............................................................................. 11

3. Revenue Allocation ................................................................................. 12

4. Rate Design .............................................................................................. 12

G. MISO Transition ................................................................................................. 14

V. RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16] ...... 14

A. Capital Investment [Germane to Preliminary Order Issue No. 17] ............... 14

B. Hurricane Rita Regulatory Asset ...................................................................... 15

C. Prepaid Pension Asset Balance .......................................................................... 23

D. FIN 48 Tax Adjustment ...................................................................................... 26

E. Cash Working Capital ........................................................................................ 30

1. The Revenue Lag Component of the Lead-Lag Study ........................ 31

2. The Expense Lead Component of the Lead-Lag Study ....................... 39

F. Self-Insurance Storm Reserve [Germane to Preliminary Order Issue

No. 5] .................................................................................................................... 45

1. The Effect of Prior Settled Cases........................................................... 46

2. OPC’s Proposed Adjustment ................................................................. 49

3. 1997 Ice Storm ......................................................................................... 54

4. Jurisdictional Separation Plan Allocation ............................................ 57

5. $50,000 Reserve Threshold .................................................................... 58

6. Hurricane Rita Regulatory Asset .......................................................... 60

SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE III

PUC DOCKET NO. 39896

7. Conclusion ............................................................................................... 60

G. Coal Inventory..................................................................................................... 61

H. Spindletop Gas Storage Facility ........................................................................ 63

I. Short Term Assets ............................................................................................... 68

J. Acquisition Adjustment ...................................................................................... 69

K. Capitalized Incentive Compensation ................................................................ 71

VI. RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4 and

11] ......................................................................................................................... 73

A. Capital Structure ................................................................................................ 73

B. Return on Equity................................................................................................. 73

1. Proxy Group ............................................................................................ 74

2. DCF Analysis ........................................................................................... 76

3. Risk Premium Analysis .......................................................................... 83

4. Comparable Earnings............................................................................. 88

5. CAPM Analysis ....................................................................................... 90

6. ALJs’ Analysis......................................................................................... 93

C. Cost of Debt ......................................................................................................... 95

D. Overall Rate of Return ....................................................................................... 95

VII. OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2,

3, 4, and 16] .......................................................................................................... 95

A. Purchased Power Capacity Expense [Germane to Supplemental

Preliminary Order Issue No. 1] ......................................................................... 95

1. The Sources of ETI’s Purchased Power................................................ 95

2. ETI’s Request Regarding PPCCs .......................................................... 99

3. Staff and Intervenors’ Opposition to ETI’s PPCCs Proposal .......... 101

4. The Intervenors’ Recommendations Regarding PPCCs ................... 106

5. The ALJs’ Analysis Regarding PPCCs ............................................... 108

B. Transmission Equalization (MSS-2) Expense ................................................ 110

C. Depreciation Expense [Germane to Preliminary Order Issue No. 12] ........ 117

1. Terminology and Methodology............................................................ 118

2. Production Plant ................................................................................... 125

3. Transmission Plant ............................................................................... 132

SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE IV

PUC DOCKET NO. 39896

4. Distribution Plant ................................................................................. 140

5. General Plant......................................................................................... 154

6. Fully Accrued Depreciation ................................................................. 160

7. Other Depreciation Issues – Accumulated Provision for

Depreciation .......................................................................................... 161

D. Labor Costs........................................................................................................ 163

1. Payroll and Related Adjustments ........................................................ 163

2. Incentive Compensation ....................................................................... 165

3. Compensation and Benefits Levels ...................................................... 175

4. Non-Qualified Executive Retirement Benefits ................................... 177

5. Employee Relocation Costs .................................................................. 179

6. Executive Perquisites ............................................................................ 180

E. Interest on Customer Deposits......................................................................... 181

F. Property (Ad Valorem) Tax Expense .............................................................. 181

G. Advertising, Dues, and Contributions............................................................. 185

H. Other Revenue-Related Adjustments ............................................................. 185

I. Federal Income Tax .......................................................................................... 185

J. River Bend Decommissioning Expense ........................................................... 186

K. Self-Insurance Storm Reserve Expense [Germane to Preliminary Order

Issue No. 5]......................................................................................................... 188

L. Spindletop Gas Storage Facility ...................................................................... 193

VIII. AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue

No. 3] .................................................................................................................. 194

A. Large Industrial & Commercial Sales Reallocation ...................................... 199

B. Administration Costs ........................................................................................ 201

C. Customer Service Operations Class ................................................................ 202

1. Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095

(Headquarter’s Credit & Collect), F3PCR73380 (Credit

Systems), and F3PCR73458 (Credit Call Outsourcing) .................... 202

2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk),

F3PCR73390 (Customer Svs Ctl - Entergy Bus), and

F3PCR73403 (Customer Issue Resolution – ES) ............................... 203

D. Distribution Operations Class ......................................................................... 203

1. Project F5PCDW0200 (Lineman’s Rodeo Expenses) ........................ 204

SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE V

PUC DOCKET NO. 39896

2. Projects F3PCTJGUSE (Joint Use With Third Party – E) and

F3PCTJTUSE (Joint Use With Third Parties – A)............................ 204

E. Energy and Fuel Management Class .............................................................. 205

1. Project F3PCWE0140 (EMO Regulatory Affairs) ............................ 205

2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense),

F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE004

(SPO Summer09RFP IM & Propslsubmt), and F3PPWET303

(SPO2008 Winter Westn RegionRFP-IM) ......................................... 206

3. Project F3PCCSPSYS (System Planning and Strategic) .................. 207

F. Environmental Service Class ........................................................................... 207

G. Federal PRG Affairs Class ............................................................................... 209

1. Project F5PPSPE044 (PMO Support Initiative-System) .................. 209

2. Project F3PPUTLDER (Utility Derivatives Compliance) ................. 210

3. Project F3PCSYSRAF (System Regulatory Affairs-Federal) .......... 211

H. Financial Services Class ................................................................................... 214

1. Projects F3PCF05700 (Corporate Planning & Analysis),

F3PCF21600 (Corp Rptg Analysis & Policy), F3PCFF1000

(Financial Forecasting), F3PPADSENT (Analytic/Decision

Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs-

Entergy) ................................................................................................. 214

2. Projects F3PCF20990 (Operations Exec VP & CFO) and

F3PCFF1001 (OCE Support)............................................................... 215

3. Project F3PCR73345 (Quick Payment Center, Adm) ....................... 216

4. Project F3PCF23936 (Manage Cash) .................................................. 217

I. Human Resources Class ................................................................................... 218

1. Project F3PCHRCCSM (HR Competitive Compensation) .............. 218

2. Projects (Non-Qualified Post-Retirement) and F5PPZNQBDU

(Non-Qual Pension/Benf-Dom Utl)...................................................... 219

J. Information Technology Class ......................................................................... 219

1. (Evaluated Receipts Settlement) ......................................................... 220

2. Project F3PCFX3555 (BOD/Executive Support) ............................... 220

K. Internal and External Communications Class ............................................... 221

L. Legal Services Class .......................................................................................... 222

1. Project F3PPCASHCT (Contractual Alternative/Cashpo) .............. 223

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PUC DOCKET NO. 39896

2. Project F5PCZLDEPT (Supervision & Support – Legal)................. 223

3. Project F3PCF99180 (Corp. Compliance Tracking Sys) .................. 223

4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and

F3PPTDHY19 (Dept. of Justice Investigation) .................................. 224

5. Project F3PCE01601 (Ferc - Access Transmission) ......................... 226

6. Project F3PCERAKTL (RAKTL Patent Matter) ............................. 227

7. Project F3PPEASTIN (Willard Eastin et al.) ..................................... 228

8. Project F3PPTCGS11 (TX Docket Competitive Generation) .......... 229

9. Project F5PCE13759 (Jenkins Class Action Suit) ............................. 230

10. Project F3PCSYSAGR (System Agreement-2001) ............................ 231

11. Project F3PCCDVDAT (Corporate Development Data Room) ....... 232

12. Project F3PPWET302 (SPO 2008 Winter Western Region) ............ 233

13. Project F3PPWET308 (SPO Calpine PPA/Project Houston) ........... 234

M. Other Expenses Class ....................................................................................... 235

1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and

F5PPKATRPT (Storm Cost Processing & Review) .......................... 235

2. Project F3PCC08500 (Executive VP, Operations)............................. 236

3. Projects F3PPBFMESI (ESI Function Migration Relocation),

F3PPBFRESI (ESI Business Function ), F3PPDRPESI (ESI

Disaster Recovery Plan Charge), F5PPBFMREL (Business

Function Migration Employee), F5PPBFRREL (Business

Function Relocation), F5PPBFRSEV (Business Function

Relocation Severance), F5PPDRPREL (Disaster Recovery Plan

Relocation), and F5PPETXRFI (2009 Texas Ike Recovery Filing) .. 236

N. Regulatory Services Class ................................................................................ 238

O. Retail Operations Class .................................................................................... 239

1. Project F5PPICCIMG (ICC – “Image” Message) ............................. 240

2. Projects F3PPR56640 (Wholesale - EGS-TX) and F3PPR56920

(Wholesale - All Jurisdictions) ............................................................. 240

P. Supply Chain Class ........................................................................................... 241

Q. Transmission and Distribution Support Class ............................................... 242

R. Tax Services Class ............................................................................................. 244

S. Transmission Operations Class ....................................................................... 245

T. Treasury Operations Class .............................................................................. 246

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PUC DOCKET NO. 39896

U. Utility and Executive Management Class ....................................................... 249

IX. JURISDICTIONAL COST ALLOCATION [Germane to Preliminary

Order Issue No. 13] ........................................................................................... 250

A. A&E 4CP ........................................................................................................... 251

B. 12CP ................................................................................................................... 252

X. CLASS COST ALLOCATION AND RATE DESIGN [Germane to

Preliminary Order Issue No. 1] ....................................................................... 255

A. Renewable Energy Credit Rider [Germane to Preliminary Order Issue

No. 19] ................................................................................................................ 255

1. ETI’s Proposed Cost Recovery ............................................................ 255

2. Opposition to ETI’s Proposal .............................................................. 256

3. ETI’s Response ...................................................................................... 260

4. ALJs’ Analysis....................................................................................... 261

B. Class Cost Allocation [Germane to Preliminary Order Issue No. 14] ......... 262

1. Municipal Franchise Fees .................................................................... 262

2. Miscellaneous Gross Receipts Taxes ................................................... 267

3. Capacity-Related Production Costs .................................................... 268

4. Transmission Costs ............................................................................... 273

C. Revenue Allocation ........................................................................................... 274

1. Argument for Moving Rates to Cost ................................................... 275

2. Argument for Gradualism ................................................................... 278

3. ALJs’ Recommendation ....................................................................... 281

D. Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20] .... 282

1. Lighting and Traffic Signal Schedules ................................................ 283

2. Demand Ratchet .................................................................................... 287

3. Large Industrial Power Service (LIPS) .............................................. 295

4. Schedulable Intermittent Pumping Service (SIPS)............................ 299

5. Standby Maintenance Service (SMS) .................................................. 303

6. Additional Facilities Charge (AFC) .................................................... 310

7. Large General Service (LGS) .............................................................. 313

8. General Service (GS) ............................................................................ 315

9. Residential Service (RS) ....................................................................... 315

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PUC DOCKET NO. 39896

XI. FUEL RECONCILIATION [Germane to Preliminary Order Issue

Nos. 21-31] ......................................................................................................... 319

A. Spindletop Gas Storage Facility ...................................................................... 324

B. Use of Current Line Losses for Fuel Cost Allocation .................................... 325

C. ETI’s Special Circumstances Request ............................................................ 326

XII. OTHER ISSUES ............................................................................................... 327

A. MISO Transition Expenses [Germane to Preliminary Order Issue

Nos. 6-8 and Docket No. 39741 Preliminary Order Issue Nos. 1-9] ............. 327

1. Deferred Accounting............................................................................. 329

2. Base Rate Recovery............................................................................... 336

B. TCRF Baseline [Germane to Supplemental Preliminary Order Issue

No. 2] .................................................................................................................. 338

C. DCRF Baseline [Germane to Supplemental Preliminary Order Issue

No. 2] .................................................................................................................. 338

D. Purchased Power Capacity Cost Baseline [Germane to Supplemental

Preliminary Order Issue No. 1] ....................................................................... 339

XIII. CONCLUSION ................................................................................................. 341

XIV. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND

ORDERING PARAGRAPHS .......................................................................... 341

A. Findings of Fact ................................................................................................. 341

B. Conclusions of Law ........................................................................................... 364

C. Proposed Ordering Paragraphs ...................................................................... 366

List of Acronyms and Defined Terms

Attachment A

List of Acronyms and Defined Terms

TERM DEFINITION

12CP 12 Coincident Peak

A&E 4CP Average and Excess, 4 Coincident Peak

A&P Average and Single Coincident Peak

ADFIT Accumulated Deferred Federal Income Tax

AFC Additional Facilities Charge

AFUDC Allowance for Funds Used During Construction

ALJs Administrative Law Judges

BCII/U3 Big Cajun II, Unit 3

Brazos Brazos Electric Cooperative, Inc.

Calpine Calpine Energy Services

Contract for the purchase of 485 MW of capacity from

Carville Contract Calpine’s Carville Energy Center

CAPM Capital Asset Pricing Model

CenterPoint CenterPoint Energy Houston Electric, LLC

CGS Competitive Generation Service

CI Conformance Index

Anahuac, Beaumont, Bridge City, Cleveland, Conroe,

Dayton, Groves, Houston, Huntsville, Montgomery,

Navasota, Nederland, Oak Ridge North, Orange, Pine

Forest, Rose City, Pinehurst, Port Arthur, Port Neches,

Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and

Cities West Orange, Texas

Commission Public Utility Commission of Texas

Company Entergy Texas, Inc.

CP Coincident Peak

CWIP Construction Work in Progress

DCF Discounted Cash Flow

DCRF Distribution Cost Recovery Factor

DOE United States Department of Energy

DOJ United States Department of Justice

EAI Entergy Arkansas, Inc.

EA WBL 2009 Contract between ETI and EAI for Wholesale Base

Contract Load Resources

EGSI Entergy Gulf States, Inc., predecessor to ETI

EGSL Entergy Gulf States Louisiana, LLC

ELL Entergy Louisiana, Inc.

EMI Entergy Mississippi, Inc.

Enbridge Long-term Gas Supply Contract between ETI and Enbridge

Contract Pipeline, L.P.

ENOI Entergy New Orleans, Inc.

Entergy Entergy Corporation

TERM DEFINITION

ESI Entergy Services, Inc.

ETEC East Texas Electric Cooperative, Inc.

ETI Entergy Texas, Inc.

FAS 106 FASB Statement No. 106

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

FIN 48 Financial Interpretation Number 48

GAAP Generally Accepted Accounting Principles

GDP Gross Domestic Product

GS General Service

GSU Gulf States Utilities Company

Iowa Curves Various Known Patterns of Industrial Asset Mortality Rates

IRS Internal Revenue Service

ISB Intra-System Bill

Class action lawsuit filed in Texas district court in 2003 on

Jenkins Class behalf of all Texas retail customers served by ETI’s

Action predecessor-in-interest, EGSI

Kroger The Kroger Co.

kW Kilowatt

kWh Kilowatt-hour

LED Light Emitting Diode

LGS Large General Service

LIPS Large Industrial Power Service

MFF Municipal Franchise Fees

MGRT Miscellaneous Gross Receipts Tax

MISO Midwest Independent Transmission System Operator, Inc.

MSS-2 Schedule MSS-2 of the Entergy System Agreement

MW Megawatt

Moody’s Moody’s Investors Service

MWh Megawatt-hour

NARUC National Association of Regulatory Utility Commissioners

Nelson Nelson 6, a 550 MW Unit located in Westlake, Louisiana

O&M Operations and Maintenance

OATT Open Access Transmission Tariff

OPC Office of Public Utility Counsel

PFD Proposal for Decision

PPCCs Purchased Power Capacity Costs

PPR Purchased Power Rider

PUC Public Utility Commission of Texas

PURA Public Utility Regulatory Act

Rate Year June 1, 2012, through May 31, 2013

Reconciliation

Period July 1, 2009, through June 30, 2011

TERM DEFINITION

RECs Renewable Energy Credits

Reserve Strategic Petroleum Reserve

River Bend River Bend Nuclear Generating Station Unit No. 1

ROE Return on Equity

RRC Railroad Commission of Texas

RS Residential Service

RTO Regional Transmission Organization

S&P Standard & Poor’s

SFAS Statement of Financial Accounting Standards

SIPS Schedulable Intermittent Pumping Service

SMS Standby Maintenance Service

SOAH State Office of Administrative Hearings

Spindletop

Facility Spindletop Gas Storage Facility

SRMPA Sam Rayburn Municipal Power Agency

Staff Staff of the Public Utility Commission of Texas

State Agencies State of Texas State Agencies

T&D Transmission and Distribution

TCRF Transmission Cost Recovery Factor

Test Year July 1, 2010, through June 30, 2011

TIEC Texas Industrial Energy Consumers

Value Line Value Line Investment Survey

Wal-Mart Wal-Mart Stores, LLC, and Sam’s East, Inc.

Zacks Zacks Investment Service

SOAH DOCKET NO. XXX-XX-XXXX

PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE

INC. FOR AUTHORITY TO CHANGE §

RATES, RECONCILE FUEL COSTS, § OF

AND OBTAIN DEFERRED §

ACCOUNTING TREATMENT § ADMINISTRATIVE HEARINGS

PROPOSAL FOR DECISION

I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4]

Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail

service area located in southeastern Texas. ETI serves retail and wholesale electric customers in

Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal

Energy Regulatory Commission (FERC) regulates ETI’s wholesale electric operations.

On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed

increase in annual base rate revenues of approximately $111.8 million over adjusted revenues for the

period beginning July 1, 2010, and ending June 30, 2011 (Test Year); (2) a set of proposed tariff

schedules presented in the Electric Utility Rate Filing Package for Generating Utilities

accompanying ETI’s application and including new riders for recovery of costs related to purchased

power capacity and renewable energy credit requirements; (3) a request for final reconciliation of

ETI’s fuel and purchased power costs for the reconciliation period from July 1, 2009, to June 30,

2011 (Reconciliation Period); and (4) certain waivers to the instructions in Rate Filing Package

Schedule V accompanying ETI’s application. The rate year for ETI’s proposed changes is June 1,

2012, through May 31, 2013 (Rate Year).1 On April 13, 2012, adjusted its request for a proposed

increase in annual base rate revenues to approximately $104.8 million over adjusted Test Year

revenues.

During the hearing the parties used the term “Rate Year” to refer to the period June 2012 through May

2013. This was intended to represent the first 12 months of the rates adopted in this case. However, the rates

in this case will not go into effect (as temporary rates) until at least June 30, 2012. Nevertheless, for purposes

of this PFD, Rate Year will refer to the period June 2012 through May 2013.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 2

PUC DOCKET NO. 39896

II. JURISDICTION AND NOTICE

The Public Utility Commission of Texas (Commission or PUC) has jurisdiction over ETI and

this rate case application pursuant to Public Utility Regulatory Act (PURA) §§ 14.001, 32.001,

33.002, and 35.004. The State Office of Administrative Hearings (SOAH) has jurisdiction over the

contested case hearing, including the preparation of the proposal for decision (PFD) pursuant to

PURA § 14.053 and Tex. Gov’t Code § 2003.049(b). Those municipalities in ETI’s service area that

have not surrendered jurisdiction to the Commission continue to have exclusive original jurisdiction

over ETI’s rates, operations, and services in their respective municipalities pursuant to PURA

§ 33.001. When ETI filed its application with the Commission, it also filed the application with its

original jurisdiction cities. Pursuant to PURA §§ 32.001(b), 33.051, and 33.053, ETI appealed the

actions of the original jurisdiction cities to the Commission and had those appeals consolidated with

this docket.

ETI’s notice of its application and notice of the hearing were not contested and, therefore, do

not require further discussion but will be addressed in the proposed findings of fact and conclusions

of law.

III. PROCEDURAL HISTORY

As noted above, ETI filed its application and rate filing package on November 28, 2011. On

November 29, 2011, the Commission referred this proceeding to SOAH. On December 19, 2011,

the Commission issued its Preliminary Order setting forth 31 issues to be addressed in this

proceeding. On January 19, 2012, the Commission issued a Supplemental Preliminary Order listing

two additional issues to be considered and stating that ETI’s request for a purchased power cost

recovery rider should not be addressed in this docket.

On September 2, 2011, ETI filed an application requesting authority to defer accounting

related to its proposed transition to membership in the Midwest Independent Transmission System

Operator, Inc. (MISO). This proceeding was docketed as Docket No. 39741. On November 22,

2011, the Commission issued its Preliminary Order in Docket No. 39741 addressing certain

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 3

PUC DOCKET NO. 39896

threshold legal/policy questions and setting forth nine issues to be addressed in the proceeding. On

December 20, 2011, Docket No. 39741 was consolidated into this docket for all purposes.

The following entities were granted intervenor status in this case: Texas Industrial Energy

Consumers (TIEC); State of Texas State Agencies (State Agencies); Office of Public Utility Counsel

(OPC); the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves,

Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest,

Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor,

and West Orange (Cities); The Kroger Co. (Kroger); Wal-Mart Stores, LLC, and Sam’s East, Inc.

(Wal-Mart); East Texas Electric Cooperative, Inc. (ETEC); and the United States Department of

Energy (DOE).

The hearing on the merits convened before SOAH Administrative Law Judges (ALJs)

Thomas H. Walston, Steven D. Arnold, and Hunter Burkhalter on April 24, 2012, and continued

through May 4, 2012. The record remained open for the filing of post-hearing briefs and proposed

finds of fact and conclusions of law. On June 8, 2012, the parties filed proposed finds of fact and

conclusions of law and the record closed. As permitted by P.U.C. PROC. R. 22.261(a), ALJ Lilo D.

Pomerleau read the record and joined in writing the PFD. Number running began on June 26, 2012,

and Staff returned the final numbers to the ALJs on July 3, 2012. The parties requested that the ALJs

submit their PFD so the Commission could consider the matter at its July 27, 2012, open meeting.

The following is a list of the parties who participated in the hearing and their counsel:

PARTIES REPRESENTATIVES

ETI Steven H. Neinast, Casey Wren, and John F. Williams2

Cities Daniel J. Lawton, Stephen Mack, and Molly Mayhall

TIEC Rex. D. VanMiddlesworth, Meghan Griffiths, and James

Nortey

State of Texas Susan Kelley

OPC Sara J. Ferris

DOE Steven A. Porter

Several other attorneys appeared on behalf of ETI. The ALJs listed only the three attorneys who appeared

throughout the hearing.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 4

PUC DOCKET NO. 39896

PARTIES REPRESENTATIVES

Kroger Kurt J. Boehm

Wal-Mart Rick D. Chamberlain

Staff Scott Smyth, Joseph Younger, Jacob J. Lawler, and Jason

Haas

IV. EXECUTIVE SUMMARY

ETI proposed an overall increase of approximately $104.8 million. The ALJs recommend an

overall rate increase for ETI of $16.4 million, as shown on the schedules attached to this PFD. With

respect to ETI’s request to reconcile fuel and purchased power costs during the Reconciliation

Period, the ALJs recommend approval without change. Attachment A contains the schedules

provided by Commission Staff reflecting the ALJs’ recommendations. On issues of particular

significance, the ALJs’ recommendations are set forth below.

A. Rate Base

1. Capital Investment

ETI’s capital additions closed to plant in service between July 1, 2009, and June 30, 2011,

were prudently incurred and are used and useful in providing service to ETI’s customers.

2. Hurricane Rita Regulatory Asset

The appropriate calculation of the Hurricane Rita regulatory asset should begin with the

amount claimed by ETI in Docket No. 37744,3 less amortization accruals to the end of the Test Year

in the present case, and less the amount of additional insurance proceeds received by ETI after the

conclusion of Docket No. 37744. This produces a remaining balance of $15,175,563, which should

remain in rate base as a regulatory asset, applying a five-year amortization rate that commenced

August 15, 2010. Further, the Hurricane Rita regulatory asset should not be moved to the storm

insurance reserve.

Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 5

PUC DOCKET NO. 39896

3. Prepaid Pension Asset Balance

The construction work in progress (CWIP)-related portion of ETI’s pension asset

($25,311,236 out of the total asset) should be excluded from the asset, but accrue allowance for

funds used during construction.

4. FIN 48 Tax Adjustment

The Commission should find that $4,621,778 (representing ETI’s full FIN 48 Liability of

$5,916,461 less the $1,294,683 cash deposit ETI has made with the Internal Revenue Service (IRS)

for the FIN 48 Liability) should be added to ETI’s ADFIT and thus be used to reduce ETI’s rate

base.

5. Cash Working Capital

The ALJs recommend no changes to ETI’s cash working capital.

6. Self-Insurance Storm Reserve

The Commission should approve ETI’s Test Year-end storm reserve balance of negative

$59,799,744.

7. Coal Inventory

The full value of ETI’s coal inventory was reasonable and should be included in rate base.

8. Spindletop Gas Storage Facility

The Spindletop Gas Storage Facility (Spindletop Facility) is a used and useful facility

providing reliability and swing flexibility to ETI’s customers at a reasonable price and should be

included in rate base.

No. 37744 (Dec. 13, 2010).

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 6

PUC DOCKET NO. 39896

9. Short Term Assets

The ALJs recommend Staff’s proposal to include the following amounts in rate base:

prepayments at $8,134,351 ($916,313 more than ETI’s request); materials and supplies at

$29,285,421 ($32,847 more than ETI’s request); and fuel inventory at $52,693,485 ($1,066,490 less

than ETI’s request).

10. Acquisition Adjustment

The $1,127,778 incurred by ETI in internal acquisition costs associated with the purchase of

the Spindletop Facility was reasonable, necessary, properly incurred, and should be included in rate

base.

11. Capitalized Incentive Compensation

The Test Year for ETI’s prior ratemaking proceeding ended on June 30, 2009. The

reasonableness of ETI’s capital costs (including capitalized incentive compensation) was dealt with

by the Commission in that proceeding and is not at issue here. Thus, exclusion of capitalized

incentive compensation that is financially-based can only be made for incentive costs that ETI

capitalized during the period from July 1, 2009 (the end of the prior Test Year) through June 30,

2010 (the commencement of the current Test Year).

B. Rate of Return and Capital Structure

The ALJs recommend a return on equity (ROE) of 9.80 percent; a cost of debt of

6.74 percent; a capital structure comprised of 50.08 percent debt and 49.92 percent common equity;

and an overall rate of return of 8.27 percent. This is a downward adjustment to ETI’s request for a

10.60 percent ROE, and no change to ETI’s 6.74 percent cost of debt and 50.08/49.92 capital

structure. It compares to Staff’s proposed 9.60 percent ROE; OPC’s proposed 9.30 percent ROE;

TIEC’s proposed 9.50 percent ROE; Cities’ proposed 9.50 percent ROE; and State Agencies’

proposed 9.30 percent ROE. No party opposed ETI’s proposed 6.74 percent cost of debt or its

proposed 50.08/49.92 capital structure.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 7

PUC DOCKET NO. 39896

C. Cost of Service

1. Purchased Power Capacity Expense

ETI’s purchased power capacity costs should be set at the amount of the Company’s Test

Year level, which is $245,432,884.

2. Transmission Equalization (MSS-2) Expense

ETI should recover only the amount of expenses under Schedule MSS-2 of the Entergy

System Agreement it paid in the Test Year, $1,753,797.

3. Depreciation Expense

The interim retirements methodology should not be adopted. The values proposed by ETI

should be adopted except for the following:

Service Lives:

Account 364-40 R1.

Account 368-33 L0.5.

Net Salvage:

Production Plant- negative 5 percent.

Account 354-negative 5 percent

Account 361-negative 5 percent.

Account 362-negative 10 percent.

Account 368-negative 5 percent.

Account 369.1-negative 10 percent.

Account 369.2-negative 10 percent.

4. Labor Costs

¾ Payroll and Related Adjustments

The Commission should accept: (1) the payroll adjustments proposed in the ETI application;

and (2) the further payroll adjustments proposed by Staff as corrected by ETI.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 8

PUC DOCKET NO. 39896

¾ Incentive Compensation

ETI should not be entitled to recover its financially based incentive compensation costs.

Thus, the ALJs recommend removing $6,196,037 from ETI’s requested operation and maintenance

(O&M) expenses. Additionally, an additional reduction should be made to account for the FICA

taxes that ETI would have paid as a result of those costs.

¾ Compensation and Benefit Levels

ETI met its burden to prove the reasonableness of its base pay and incentive package costs.

It is reasonable to view market price for these categories of costs as lying within a range of +/-

10 percent of median, rather than being a single point along a spectrum. As to both base pay and the

incentive package, ETI has proven that its costs fall within such an acceptable range. Accordingly,

the ALJs recommend rejecting the adjustments sought by Cities.

¾ Nonqualified Executive Retirement Benefits

The ALJs recommend an adjustment to remove $2,114,931, representing the full costs

associated with ETI’s non-qualified executive retirement benefits.

¾ Employee Relocation Costs

The Commission should allow ETI’s relocation expenses.

¾ Executive Perquisites

The ALJs recommend an adjustment to remove $40,620, representing the full cost of ETI’s

executive perquisite costs.

5. Interest on Customer Deposits

The ALJs recommend using the active customer deposits amount of $35,872,476 and the

2012 interest rate, which produces a recommended interest expense of $43,047 ($35,872,476

multiplied by .12 percent).

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 9

PUC DOCKET NO. 39896

6. Property (Ad Valorem) Tax Expense

ETI’s property tax burden should be adjusted upward by applying the effective tax rate of

0.007435784 for the calendar year 2011 to the final, adopted Test Year-end plant in service value for

ETI.

7. Advertising, Dues, and Contributions

The ALJs recommend an adjustment to remove $12,800 from ETI’s costs of advertising,

dues and contributions.

8. Other Revenue Related Adjustments

These amounts were determined through number running and are reflected in Attachment A.

9. Federal Income Tax

The Commission should adopt ETI’s proposal on federal income taxes.

10. River Bend Decommissioning Expense

ETI’s annual decommissioning revenue requirement should reflect the most current

calculation of $1,126,000. Therefore, an adjustment of $893,000 to the pro forma cost of service is

needed to reflect the difference between the requested level for decommissioning costs of

$2,019,000 and the recommended level of $1,126,000.

11. Self-Insurance Storm Reserve Expense

The Commission should approve a total annual accrual of $8,270,000, comprised of an

annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual

accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. The ALJs

recommend approval of ETI’s proposed target reserve of $17,595,000. The Commission should

require ETI to continue recording its annual accrual until modified by future Commission orders.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 10

PUC DOCKET NO. 39896

12. Spindletop Gas Storage Facility

The ALJs recommend inclusion of the costs of operating the Spindletop Facility as requested

by ETI.

D. Affiliate Transactions

ETI agreed to remove the following affiliate transactions from its request, which the ALJs

recommend be approved: (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the

amount of $2,553; (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of

$14,288; and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

Except as noted below, all remaining affiliate transactions should be approved. The ALJs

recommend that the following affiliate transactions not be included:

¾ $356,151 (which figure includes the $112,531 agreed to by ETI) of costs

associated with Projects F5PCZUBENQ (Non-Qualified Post

Retirement) and F5PPZNQBDU (Non Qual Pension/Benf Dom Utl);

¾ $10,279 of costs associated with Project F3PPFXERSP (Evaluated

Receipts Settlement);

¾ $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et

al); and

¾ $171,032 of costs associated with Project F3PPE9981S (Integrated

Energy Management for ESI).

E. Jurisdictional Cost Allocation

The ALJs recommend the use of 12 Coincident Peak (12CP) to allocate capacity-related

production costs between the retail and wholesale jurisdictions.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 11

PUC DOCKET NO. 39896

F. Class Cost Allocation

1. Renewable Energy Credit Rider

The Commission should deny ETI’s request to institute a renewable energy credit rider, and

the Test Year expense of $623,303 should be used for setting rates in this case. Finally, the

Renewable Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an

adjustment to the credit rates to reflect the Test Year data used to set ETI’s base rates.

2. Class Cost Allocation

The parties generally agreed that ETI’s cost-of-service study comported with accepted

industry practices, but some parties had issues with specific items discussed below.

(a) Municipal Franchise Fees

Municipal franchise fees should be allocated on the basis of in-city kilowatt-hour (kWh)

sales, without an adjustment for the municipal franchise fee rate in the municipality in which a given

kWh sale occurred. The ALJs recommend adoption of ETI’s proposal to collect costs from all

customers taking service from the system.

(b) Miscellaneous Gross Receipts Tax

Similar to municipal franchise fees, miscellaneous gross receipts taxes should be allocated to

the rate classes according to ETI’s cost of service study.

The ALJs recommend the use of Average and Excess 4 Coincident Peak (A&E 4CP) to

allocate capacity-related production costs, as proposed by ETI. The ALJs do not find sufficient

support to allocate the reserve equalization payments differently than other capacity-related

production costs.

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PUC DOCKET NO. 39896

(d) Transmission Costs

ETI’s proposed methodology for allocation of transmission costs should be approved. A&E

4CP is a well-accepted method for allocating such costs.

3. Revenue Allocation

Revenue allocation in this case should be based on each class’s cost of service and consistent

with the ALJs’ recommendations in the PFD that impact revenue allocation.

4. Rate Design

(a) Lighting and Traffic Signal Schedules

ETI should be directed to perform a light emitting diode (LED) lighting cost study before

significant changes are made to its lighting rates. The ALJs further recommend that ETI conduct

this study before filing its next rate case and provide the results of any completed study to Cities and

interested parties. The study should include detailed information regarding differences in the cost of

serving LED and non-LED lighting customers, if ETI currently has LED lighting customers taking

service. ETI should modify the applicable tariffs to eliminate its fee for any replacement of a

functioning light with a lower-wattage bulb.

(b) Demand Ratchet

ETI’s proposed Large Industrial Power Service (LIPS) tariff should be amended to include

the language proposed by DOE witness Etheridge.

The ALJs recommend the adoption of a $630 customer charge for this customer class, a

slight decrease in the LIPS energy charges, and an increase in the demand charges from current rates

for this class, as proposed by Staff witness Abbott.

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PUC DOCKET NO. 39896

(d) Schedulable Intermittent Pumping Service

The Commission should adopt the Schedulable Intermittent Pumping Service rider proposed

by DOE witness Etheridge.

(e) Standby Maintenance Service

The Commission should adopt the changes to Schedule SMS recommended by TIEC, with

the exception of a $6,000 customer charge. Consistent with the ALJs’ recommendation that a new

LIPS charge of $630 is reasonable, the Standby Maintenance Service (SMS) charge should be

limited to $630 and not apply if a Schedule SMS customer also purchased supplementary power

under another applicable rate.

(f) Additional Facilities Charge

Schedule AFC should be changed in accordance with TIEC’s recommendations and those

recommended numbers should be reduced in proportion to any authorized reduction in ETI’s

proposed rate of return, O&M expense, and property tax expense.

(g) Large General Service

Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand

ratchet, and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is

applicable to this class

(h) General Service

The Commission should adopt the decrease in the Schedule GS customer charge to $39.91

from the current (and Company proposed) rate of $41.09, as well as Staff’s recommended decrease

in energy charges. Schedule GS also has a demand ratchet, and the ALJs’ recommendation for the

elimination of ETI’s LIPS demand ratchet is applicable to this class.

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PUC DOCKET NO. 39896

(i) Residential Service

ETI’s declining block winter rates provide a disincentive to energy efficiency. The ALJs

recommend an initial 20 percent reduction, followed by 20 percent subsequent reductions of the

differential in the next three rate cases unless ETI provides sufficient evidence that such changes are

unjust and unreasonable.

G. MISO Transition

The Commission should deny ETI’s request for deferred accounting of its MISO transition

expenses to be incurred on or after January 1, 2011. However, the Commission should authorize

ETI to include $2.4 million of MISO transition expense in base rates set in the present case, based on

a five-year amortization of $12 million in total projected expenses. Further, the Commission should

authorize ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of

the Test Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of

$2,452,800.

V. RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16]

A. Capital Investment [Germane to Preliminary Order Issue No. 17]

ETI presented for review $408,078,600 in capital additions closed to plant in service between

July 1, 2009, and June 30, 2011; that is, from the end of the test year in the Company’s last base rate

case, which was Docket No. 37744, through the Test Year presented in this case. The capital

additions were detailed in the testimony and exhibits of the following Company witnesses: Garrison

(Generation), McCulla (Transmission), Corkran (Distribution), Stokes (Customer Service), Brown

(Information Technology), Plauche (Administrative), Cicio (System Planning and Operations),

Hunter (Supply Chain), May (Regulatory), and Sloan (Legal).4 The evidence shows that these

ETI Ex. 27 (Garrison Direct) at 20-28 and WWG-4; ETI Ex. 32 (McCulla Direct) at 64-92 and MFM-16;

ETI Ex. 25 (Corkran Direct) at 78-108 and SBC-3; ETI Ex. 37A (Roman Direct, adopted by Stokes) at 121-

125 and AFR-5; ETI Ex. 24 (Brown Direct) at 29-37 and JFB-3; ETI Ex. 20 (Plauche Direct) at 37-44 and

TCP-11; ETI Ex. 39 (Cicio Direct) at 71-75 and PJC-6; ETI Ex. 16 (Hunter Direct) at 34-38 and JMH-7; ETI

Ex. 7 (May Direct) at 53-54 and PRM-3; and ETI Ex. 38 (Sloan Direct) at 37-43 and RDS-4.

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PUC DOCKET NO. 39896

capital additions were prudently incurred and are used and useful in providing service to ETI’s

customers. No party challenged any of the capital additions or the costs thereof, and the ALJs find

no reason to do so either.

B. Hurricane Rita Regulatory Asset

Hurricane Rita struck the upper Texas coast in September 2005, causing extensive property

damage. In 2006, the Texas Legislature enacted PURA Chapter 39 to authorize electric utilities such

as ETI to securitize the recovery of their reconstruction costs incurred as a result of Hurricane Rita.

Under the statute, the amount of reconstruction costs to be securitized had to be reduced by the

insurance proceeds and government grants received by a utility. If additional insurance or grant

proceeds were received after the securitization order was approved, the Commission was required to

take those amounts into account in the utility’s next base rate case. This was provided in

Section 39.459(c) of PURA:

To the extent a utility subject to this subchapter receives insurance proceeds,

governmental grants, or any other source of funding that compensates it for hurricane

reconstruction costs, those amounts shall be used to reduce the utility’s hurricane

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